bipartisan policy center and american clean skies ... · bipartisan policy center and american...
TRANSCRIPT
TASK FORCE ON ENSURING STABLE NATURAL GAS MARKETS
B I PA RT I S A N P O L I C Y C E N T E R A N DA M E R I C A N C L E A N S K I E S F O U N D AT I O N ’ S
Disclaimer
This report is the product of a Task Force with participants of diverse expertise and affiliations,
addressing many complex and contentious topics. It is inevitable that arriving at a consensus
document in these circumstances entailed compromises. Accordingly, it should not be assumed
that every member is entirely satisfied with every formulation in this document, or even that all
participants would agree with any given recommendation if it were taken in isolation. Rather, this
group reached consensus on these recommendations as a package, which taken as a whole offers
a balanced approach to the issue.
It is also important to note that this report is a product solely of participants from the BPC–ACSF
convened Task Force on Ensuring Stable Natural Gas Markets. The views expressed here do not
necessarily reflect those of the Bipartisan Policy Center or the American Clean Skies Foundation.
Acknowledgements
The Bipartisan Policy Center and the American Clean Skies Foundation would like to express
their thanks for the strong support of their funders.
Special appreciation is due to the Task Force staff. In particular David Rosner, Associate
Director, and Lourdes Long, Senior Policy Analyst, at the BPC and Jerry Hinkle, Vice President,
and Geoff Bromaghim, Energy Policy Research Associate, at ACSF. Additionally, the Task
Force membership and staff gratefully acknowledge Joel Bluestein and Bruce Henning of ICF
International for the substantial guidance, research, and support that they offered throughout
the course of this effort. Thanks also to Marika Tatsutani for editing the Task Force report.
Additionally, thanks are due to the authors of the 11 papers that were commissioned by the Task
Force as part of this process. These authors are detailed further in Appendix B of the report.
TASK FORCE ON ENSURING STABLE NATURAL GAS MARKETS
B I PA RT I S A N P O L I C Y C E N T E R A N DA M E R I C A N C L E A N S K I E S F O U N D AT I O N ’ S
CONTENTS
Letter from the Co-Chairs ...................................................................................................................2
Task Force on Ensuring Stable Natural Gas Markets – Sponsors, Participants and Staff ..............4
Executive Summary ............................................................................................................................ 6
I. Introduction ................................................................................................................................. 14
A. Overview .................................................................................................................................. 14
B. Structure of Task Force and Work Plan .................................................................................16
C. Report Structure ......................................................................................................................16
II. Background on Natural Gas Markets, Use and Supply ............................................................. 18
A. Uses and Markets.................................................................................................................... 18
B. History and Sources of Price Variability ................................................................................22
C. Impact of Gas Pricing and Variability on the Economy ...................................................... 26
i. Impact on Small Consumers ..............................................................................................27
ii. Impact on Large Consumers ............................................................................................ 28
iii. Impact on Energy Production and Delivery Companies ................................................ 31
III. Approaches to Improving Mid- to Long-Term Price Stability ...................................................32
A. Supply and Infrastructure....................................................................................................... 33
i. Shale and the New Gas Supply Paradigm .......................................................................... 33
ii. Environmental Impacts Associated with Shale Gas .........................................................38
iii. Imports: Liquefied Natural Gas ........................................................................................41
iv. Storage ................................................................................................................................43
v. Pipelines .............................................................................................................................. 46
B. New Approaches to Contracting ............................................................................................ 48
i. Common Contract Terms ................................................................................................... 48
ii. History of Long-term Gas Contracts ................................................................................ 49
iii. Renewed Interest in Long-term Gas Contracts ...............................................................50
iv. Contract Accounting Practices .......................................................................................... 51
C. Financial and Physical Hedging ............................................................................................. 57
i. Objectives, Costs and Limitations of Hedging .................................................................. 57
ii. State Regulatory Treatment of Electric and Gas Utility Hedging Programs ..................58
D. Potential Impact of Financial Reform on Hedging Options ................................................59
IV. Conclusions, Recommendations and Next Steps .....................................................................60
V. Appendices ..................................................................................................................................66
A. Workshops and Participants .................................................................................................. 67
B. Commissioned Papers ........................................................................................................... 68
Index of Figures
Figure 1 - Natural Gas Futures Prices - 2008 to 2010 .......................................................................8
Figure 2 - U.S. Energy Mix - 2010 ....................................................................................................19
Figure 3 - U.S. Energy Consumption by Sector - 2010 .................................................................. 20
Figure 4 - U.S. Natural Gas Price 1976 to 2010 (Nominal dollars) ................................................ 21
Figure 5 - U.S. Natural Gas Balance and Pricing ............................................................................ 24
Figure 6 - Indexed Fuel Prices - 1995 to 2010 .................................................................................25
Figure 7 - Natural Gas Futures Prices - 2008 to 2010 ....................................................................27
Figure 8 - Diagram of Hydraulic Fracturing Process ......................................................................34
Figure 9 - Natural Gas Production, 1998 to 2020 .......................................................................... 35
Figure 10 - U.S. Energy Information Administration Supply Forecast - 2005 .............................. 35
Figure 11 - U.S. Energy Information Administration
U.S. Dry Gas Production Forecast - 2011 .......................................................................36
Figure 12 - Shale Gas Basins in North America .............................................................................. 37
Figure 13 - U.S. Natural Gas Resource Cost Curves by Type........................................................... 37
Figure 14 - Evolution of U.S. Natural Gas Supply............................................................................41
Figure 15 - U.S. Underground Storage Locations ........................................................................... 44
Index of Tables
Table 1. Published Estimates of U.S. Lower 48 Recoverable Shale Gas (Tcf) ................................36
Table 2. Gas Pipeline Expansions in the Northeast .........................................................................47
Letter from the Co-Chairs
Over the last year, we have been privileged to co-chair an unusual and highly productive Task Force
that was formed to review the conditions for creating a more certain U.S. market for using and
producing natural gas.
The Task Force brought together a remarkable group of industry participants and experts,
including industrial consumers, electric utilities, independent and integrated gas producers,
chemical companies, public utility regulators, environmental experts, financial analysts and
consumer advocates. Together, we approached our inquiry from a wide range of perspectives, but
with a common interest in working to ensure that market conditions support increased investment
in efficient gas production and end-use technologies.
This is an important public-interest challenge with far-reaching consequences. The United
States recently became the world’s largest natural gas producer. Meanwhile, in a few short years,
technology advances combined with new shale gas discoveries have more than tripled estimates
of the nation’s economically recoverable natural gas resources. In the context of a dramatically
improved supply outlook, expanding our use of this comparatively clean–burning, domestic fuel in
an efficient manner is a winning proposition for consumers, for America’s economy and industrial
competitiveness, for the environment, and for our nation’s energy security.
2 Task Force on Ensuring Stable Natural Gas Markets
Task Force on Ensuring Stable Natural Gas Markets 3
Good news, in other words, rather than concern over some pending crisis, provided the inspiration
and backdrop for our deliberations. But Task Force members were also aware that the price
instability that has come to be associated with natural gas markets in past years still raises
investment uncertainty for gas suppliers and users alike. And so long as this is the case, some of
the opportunities associated with efficient applications of gas technologies are likely to be realized
more slowly than need be.
The findings and recommendations in this report reflect optimism that the robust supply horizon
for natural gas presents fresh opportunities—not only to move beyond prior market concerns but
to develop new tools for managing price uncertainty. Fundamental changes in the domestic supply
and demand balance for natural gas, including an unprecedented level of available storage and
import capacity, should allow markets to function more efficiently and fluidly in the future. This
should create more favorable investment conditions and significantly dampen the potential for
destructive cycles of price volatility and market instability.
At the same time, our work emphasizes the importance of actions by regulators and private market
participants to ensure that these positive trends materialize as quickly and fully as possible. In
particular, we urge the industry and regulators to re-evaluate the scope for using longer-term gas
purchasing arrangements for managing price risk in the context of a diversified supply portfolio.
The report also stresses the need for environmental protections so as to secure continued access
to, and public support for, the development of shale gas reserves. Finally, though the Task Force
did not address issues of aging infrastructure or pipeline integrity, we acknowledge that concerns
involving the safe handling and transportation of natural gas must be fully vetted and satisfactorily
resolved. Public safety is not an area for compromise.
Our recommendations are pointed at government policymakers, federal regulators, state utility
commissions, producers and major consumers. We welcome feedback and look forward to
working with all stakeholders to leverage the considerable potential of natural gas in building a
clean energy foundation for American prosperity.
___________________________
Norm Szydlowski
Bipartisan Policy Center;
President & CEO
SemGroup Corporation
March 2011
Washington, DC
___________________________
Gregory C. Staple
CEO
American Clean Skies Foundation
Task Force on Ensuring Stable Natural Gas Markets – Sponsors, Participants and Staff
Sponsoring Task Force Members
Gregory C. Staple Task Force Co-Chair
Chief Executive Officer
American Clean Skies Foundation
Norm SzydlowskiTask Force Co-Chair
Bipartisan Policy Center;
President & CEO
SemGroup Corporation
Ken Bromfield U.S. Commercial Director, Energy Business
The Dow Chemical Company
Carlton Buford Lead Economist
The Williams Companies
Peter Sheffield Vice President, Energy Policy and
Government Affairs
Spectra Energy Corporation
Ralph Cavanagh Senior Attorney and Co-Director,
Energy Program
Natural Resources Defense Council
Paula GantSenior Vice President for Policy and Planning
American Gas Association
Carl Haga Director, Gas Services
Southern Company
Byron Harris Director
West Virginia Consumer Advocate Division
Marianne Kah Chief Economist, Planning and Strategy
ConocoPhillips
Todd Strauss Senior Director, Energy Policy, Planning
and Analysis
Pacific Gas & Electric Company
Additional Task Force Members
Task Force Staff
Colette Honorable Chairman
Arkansas Public Service Commission
Sharon Nelson Former Chair, Board of Directors
Consumers Union;
Former Chief, Consumer Protection Division,
Washington Attorney General’s Office
Sue Tierney Managing Principal
Analysis Group, Inc.;
Former Assistant Secretary of Energy
Bill Wince Vice President, Transportation and Business Development
Chesapeake Energy Marketing, Inc.
Marty Zimmerman Professor
Ross School of Business, University of Michigan;
Former Group Vice President, Corporate Affairs,
Ford Motor Company
BPC
Lourdes Long Senior Policy Analyst
Bipartisan Policy Center
David Rosner Associate Director
Bipartisan Policy Center
ACSF
Geoff Bromaghim Energy Policy Research Associate
American Clean Skies Foundation
Jerry Hinkle Vice President, Policy and Research
American Clean Skies Foundation
6 Task Force on Ensuring Stable Natural Gas Markets
NNatural gas is one of America’s most important
energy resources. Comparatively clean burning and
less carbon intensive than oil or coal, it is used as
a fuel in a wide variety of applications throughout
the economy and as a chemical feedstock in the
industrial sector. Until recently, however, U.S. supplies
of natural gas were also perceived as relatively
limited. This meant that the potential to advance
long-term environmental or energy security goals
through expanded reliance on domestic natural gas
would necessarily be constrained. It also implied
that natural gas markets would continue to be
susceptible to the price run-ups and volatility that
had captured news headlines in the mid-1990s and
again in the early and mid-2000s.
EXECUTIVE SUMMARY
Task Force on Ensuring Stable Natural Gas Markets 7
This picture of natural gas as an attractive
but limited domestic resource has changed
dramatically in just a few short years, along with
the assumptions that go with it. Technological
advances in horizontal drilling and hydraulic
fracturing have unlocked a tremendous volume
of additional gas resources in North American
shale gas formations. These developments have
altered the supply outlook for natural gas such
that identified domestic resources are now
thought to be sufficient—barring environmental
or other impediments to tapping these reserves—
to support more than 100 years of demand at
present levels of consumption.
With these developments in gas supply, the
market for natural gas has shifted in a profound
way. Price expectations, as shown in Figure 1,
have declined dramatically as the full impact of
new technology for identifying and developing
natural gas supplies has been recognized.
In combination with recent investments to
expand capacity for storing, transporting
and importing natural gas, these supply
developments should allow the U.S. market
to respond more smoothly to future demand
fluctuations and should substantially alleviate
long-standing supply adequacy concerns.
Given the availability of highly efficient
conversion and end-use technologies for
natural gas, this is good news from multiple
perspectives—whether the objective is to
reduce pollutant emissions, reduce U.S.
dependence on imported energy sources, or
maintain a competitive industrial base.
Realizing and maximizing these benefits,
however, will require that investors have
confidence in the mid- to long-term stability
of natural gas prices. On the demand side,
residential and commercial consumers,
electricity generators and large industrial users
will need confidence that gas prices will be
TECHNOLOGICAL ADVANCES
IN HORIZONTAL DRILLING AND
HYDRAULIC FRACTURING HAVE
UNLOCKED A TREMENDOUS
VOLUME OF ADDITIONAL GAS
RESOURCES IN NORTH AMERICAN
SHALE GAS FORMATIONS.
8 Task Force on Ensuring Stable Natural Gas Markets
TOGETHER WITH A VASTLY
IMPROVED SUPPLY OUTLOOK,
THE TASK FORCE BELIEVES
THAT A SMALL NUMBER OF
PRACTICAL REGULATORY AND
POLICY MEASURES WOULD
GO A LONG WAY TOWARD
PROVIDING THE CONFIDENCE
NEEDED TO SUPPORT
A SIGNIFICANT EXPANSION
IN THE DEPLOYMENT
OF EFFICIENT NATURAL
GAS TECHNOLOGIES.
1 For a list of commissioned research papers see Appendix B.
sufficiently competitive and stable to make
investments in new gas-using technologies cost
effective. On the supply side, the natural gas
industry needs confidence that market demand
and prices will justify new investments in
expanded production capacity. Both sides would
benefit from avoiding the price variability that
has characterized natural gas markets in the
past, when spikes hurt consumers and created
difficulties for gas-dependent industries.
The Task Force on Ensuring Stable Natural
Gas Markets
The Task Force on Ensuring Stable Natural Gas
Markets (hereafter “Task Force”) was jointly
convened by the Bipartisan Policy Center and
the American Clean Skies Foundation in March
2010 to examine historic causes of instability
in natural gas markets and to explore potential
remedies. The membership of the Task Force is
unique in its diversity and unique in the sense
that it brings together key stakeholders from
both sides of the supply–demand equation.
Individual Task Force members are listed in the
Preface; they represent natural gas producers,
transporters and distributors, consumer groups
and large industrial users, as well as independent
experts, consumer advocates, state regulatory
commissions and environmental groups.
Over the course of five meetings and with the
help of original commissioned research on
several related topics, the Task Force examined
the causes of past variability in natural gas
prices and considered how recent shale gas
discoveries and other, infrastructure-related
developments affect the likelihood that similar
price shocks might recur in the foreseeable
future.1 The Task Force also developed a
comprehensive set of recommendations aimed
at bolstering consumer, policy maker and
investor confidence in the stability of future gas
markets and at improving the tools available for
effective price risk management.
$14
$12
$10
$8
$6
$4
$2
$0
Natural Gas Futures Prices NYMEX(Nominal USD per MMBtu)
Jan 08
Jun 08
Nov 08
Apr 0
9
Sep 09
Feb 10
Jul 1
0
Dec 10
May
11
Oct 1
1
Mar 12
Aug 12
Jan 13
Jun 13
Nov 13
Apr 1
4
Sep 14
Feb 15
Jul 1
5
Dec 15
May
16
Oct 1
6
Mar 17
Aug 17
Jan 18
Jun 18
Nov 18
Apr 1
9
Sep 19
Feb 20
Jul 2
0
Dec 20
Historical HH 1/8/07 1/7/08 1/7/09 1/7/10 1/7/11
Figure 1. Natural Gas Futures Prices - 2008 to 2010
Note: Henry Hub (HH), Louisiana, is a major production area delivery point in the gas industry. The NYMEX Natural Gas Futures contract uses the Henry Hub price as the reference price.
Source: New York Mercantile Exchange.
Task Force on Ensuring Stable Natural Gas Markets 9
Together with a vastly improved supply outlook,
the Task Force believes that a small number of
practical regulatory and policy measures would
go a long way toward providing the confidence
needed to support a significant expansion in the
deployment of efficient natural gas technologies
and toward capturing the economic and
environmental benefits such an expansion
would provide.
Key Task Force Findings and
Recommendations
1. Recent developments allowing for the
economic extraction of natural gas from shale
formations reduce the susceptibility of gas
markets to price instability and provide an
opportunity to expand the efficient use of
natural gas in the United States.
2. Government policy at the federal, state and
municipal level should encourage and facilitate
the development of domestic natural gas
resources, subject to appropriate environmental
safeguards. Balanced fiscal and regulatory
policies will enable an increased supply of
natural gas to be brought to market at more
stable prices. Conversely, policies that discourage
the development of domestic natural gas
resources, that discourage demand, or that drive
or mandate inelastic demand will disrupt the
supply-demand balance, with adverse effects on
the stability of natural gas prices and investment
decisions by energy-intensive manufacturers.
3. The efficient use of natural gas has the
potential to reduce harmful air emissions,
improve energy security, and increase operating
rates and levels of capital investment in energy-
intensive industries.
4. Public and private policy makers should
remove barriers to using a diverse portfolio of
natural gas contracting structures and hedging
options. Long-term contracts and hedging
programs are valuable tools to manage natural
gas price risk. Policies, including tax measures
and accounting rules, that unnecessarily
restrict the use or raise the costs of these risk
management tools should be avoided.
10 Task Force on Ensuring Stable Natural Gas Markets
2 National Association of Regulatory Utility Commissioners. Resolution on Long-Term Contracting. Adopted by the NARUC on November 16, 2005. http://www.naruc.org/Resolutions/GAS-1Long-TermContracting.pdf
THE EFFICIENT USE OF
NATURAL GAS HAS THE
POTENTIAL TO REDUCE
HARMFUL AIR EMISSIONS,
IMPROVE ENERGY
SECURITY, AND INCREASE
OPERATING RATES AND
LEVELS OF CAPITAL
INVESTMENT IN ENERGY-
INTENSIVE INDUSTRIES.
5. The National Association of Regulatory Utility
Commissioners (NARUC) should consider
the merits of diversified natural gas portfolios,
including hedging and longer-term natural
gas contracts, building on its 2005 resolution.2
Specifically, NARUC should examine:
a. Whether the current focus on shorter-
term contracts, first-of-the-month pricing
provisions and spot market prices
supports the goal of enhancing price
stability for end users,
b. The pros and cons of long-term contracts
for regulators, regulated utilities and their
customers,
c. The regulatory risk issues associated with
long-term contracts and the issues of
utility commission pre-approval of long-
term contracts and the look-back risk for
regulated entities, and
d. State practices that limit or encourage
long-term contracting.
6. As the Commodity Futures Trading
Commission (CFTC) implements financial
reform legislation, including specifically Title
VII of the Dodd-Frank Wall Street Reform and
Consumer Protection Act of 2010 (Pub. L.
111-203), the CFTC should preserve the ability
of natural gas end users to cost effectively
utilize the derivatives markets to manage their
commercial risk exposure. In addition, the
CFTC should consider the potential impact of
any new rulemaking on liquidity in the natural
gas derivatives market, as reduced liquidity
could have an adverse affect on natural gas
price stability.
7. Policy makers should recognize the
important role of natural gas pipeline and
storage infrastructure and existing import
infrastructure in promoting stable gas prices.
Policies to support the development of a fully
functional and safe gas transmission and storage
infrastructure both now and in the future,
including streamlined regulatory approval and
options for market-based rates for new storage
in the United States, should be continued.
Task Force on Ensuring Stable Natural Gas Markets 11
NATURAL GAS PLAYS A UNIQUELY
IMPORTANT ROLE IN THE U.S.
ECONOMY BECAUSE IT IS USED
ACROSS MULTIPLE SECTORS
OF THE ECONOMY AND IN A WIDE
VARIETY OF APPLICATIONS.
8. Finally, regulators should be mindful of the
lead time required for markets and market
participants to adjust to new policies.
Background and Context for the Task
Force Recommendations
The full Task Force report describes in detail
the evolution of the U.S. natural gas market
over the last half century and the specific
causes behind more recent episodes of price
variability in this market. Several points from
that discussion are worth highlighting as part
of this summary because they provide the
context and rationale for Task Force findings
and recommendations:
� Natural gas plays a uniquely important role in
the U.S. economy, both because it is a major
contributor to the nation’s overall energy
portfolio (second only to petroleum in terms
of total primary energy consumption) and
because it is used across multiple sectors of the
economy and in a wide variety of applications.
� U.S. natural gas markets have only been
open and competitive for about 17 years.
Starting in the 1950s and until the early 1990s,
concerns about domestic supply adequacy
and a desire to direct limited gas resources to
particular uses led to extensive regulation
and government intervention. This approach
resulted in mostly stable prices but also led
to severe supply shortages and significant
market distortions.
� After the deregulation of gas commodity
markets in the early 1990s, a combination of
declining production capacity and increasing
demand led to a tightening supply/demand
balance. Prices spiked sharply in 2000 and
again in 2005 in the wake of hurricanes Rita
and Katrina, which temporarily curtailed gas
supplies from the Gulf of Mexico. Though
prices fell again after both of these events,
they did not return to the levels that had been
typical of earlier decades; in fact, prices
remained high relative to historic norms until
the economic downturn of 2008 and the rapid
growth in gas production from shale and
other “unconventional” gas resources.
� Large gas-dependent industrial users, especially
if they compete with producers from countries
with access to low cost natural gas, are likely to
be especially hard hit by major price run-ups
in the U.S. market. Higher natural gas prices
are also passed on to smaller users such as
homes and businesses. Regulated gas
distribution companies are required to pass on
the cost of gas they purchase for consumers
at cost (without price markup or markdown).
In the electric power sector, companies
interested in adding or replacing generation
capacity must weigh uncertainty about
future fuel prices in making technology and
resource investments.
� Because U.S. capacity to import natural gas
from overseas suppliers has historically been
very limited, the market for this commodity
is primarily national (rather than global, as
in the case of petroleum). This has meant
that prices are tightly coupled to North
American supply and domestic demand. In
the early 2000s, an expectation that domestic
demand would soon begin to outstrip
domestic production capacity led to higher
prices and prompted new investments in the
physical infrastructure needed to import and
store natural gas. As a result, U.S. capacity
for receiving liquefied natural gas (LNG)
shipments (now equivalent to roughly 20
percent of annual demand) and U.S. capacity
for storing gas (likewise equivalent to about
20 percent of annual demand) is greater than
at any time in the past. Together with a robust
pipeline network, these changes in import
12 Task Force on Ensuring Stable Natural Gas Markets
IN RECENT YEARS, A NUMBER
OF STAKEHOLDERS AND
OBSERVERS HAVE CALLED
FOR A RETURN TO A GREATER
RELIANCE ON LONG-TERM
CONTRACTS BETWEEN GAS
SUPPLIERS AND PURCHASERS
TO HELP ADDRESS PRICE
RISKS AND TO PROMOTE
PRICE STABILITY.
and storage capacity by themselves would
have been expected to help mitigate the market
volatility and upward price pressures that
emerged in the last decade.
� The years between 2005 and 2010, however,
saw an even more dramatic change in the
domestic supply picture for natural gas as it
became clear that recoverable U.S. reserves of
shale gas are far more extensive and broadly
distributed than previously thought. In 2003,
the National Petroleum Council estimated
recoverable shale gas resources at 35 trillion
cubic feet (Tcf). Six years later, in 2009,
another widely respected group, the Potential
Gas Committee, estimated the resource
base at more than 616 Tcf, based on 2008
industrywide data (Table 1).
� The technologies used to extract shale gas,
including horizontal drilling and sequenced,
multi-stage hydraulic fracturing, were
pioneered in the 1980s. Since then, the shale
gas industry has matured and the technologies
involved have become more sophisticated
and cost-effective. ICF International, Inc.
recently estimated that almost 1,500 Tcf of
shale gas can be produced at prices below
$8 per million Btu (MMBtu). By comparison,
annual U.S. consumption of natural gas
currently totals approximately 22 Tcf.
� Ample domestic supply will be among the
most important factors promoting moderate
and stable natural gas prices over the next
several decades. This result, however, is
predicated on the successful management
of environmental concerns associated with
current methods of shale gas production
and on the willingness of local communities
to accept this type of development, even in
areas with little prior exposure to energy
production activities.
� The most important environmental issues
related to shale gas production include
the potential for water contamination if
proper procedures aren’t followed; water
consumption for fracturing operations,
particularly in areas where water resources
are already stressed; and air emissions and
disruption associated with the use of heavy
equipment and related infrastructure (e.g.,
roads, drill pads and gathering lines). If
environmental and other local impacts are
not properly managed and remediated,
an increasing number of communities
could begin to oppose shale gas production
activities. To address these impacts, several
states are currently revisiting existing
regulations for shale gas extraction; in New
York, meanwhile, the state Assembly voted
in August 2010 to impose a moratorium on
hydraulic fracturing until state regulatory
authorities could conduct a thorough review
of associated environmental risks and of
the adequacy of current environmental
protections and safeguards.
� Contract mechanisms to hedge future price
variability are important tools for managing
risk in commodities markets, including
the natural gas market. In recent years, a
number of stakeholders and observers have
called for a return to a greater reliance on
long-term contracts between gas suppliers
and purchasers to help address price risks
and to promote price stability. Such contracts
can play a useful role as part of a diversified
portfolio. However, the current fair value
accounting treatment for some of these
contracts (e.g., quarterly market pricing, also
known as "mark-to-market") may discourage
some buyers and sellers from using such
contracts due to the unknown impact of future
quarterly disclosures to investors on corporate
balance sheets. Similarly, some public utility
commission (PUC) rules (e.g., regarding when
Task Force on Ensuring Stable Natural Gas Markets 13
gas purchase costs may be recovered from
ratepayers) may also discourage regulated
gas suppliers from using such contracts to
manage the impact of price variability even
though they might benefit customers.
� It is also important to recognize that few
long-term contracts (even when such
contracts were more common) are or have
been truly “fixed price” in the sense that
both parties are locked into a single specified
price regardless of other market or regulatory
developments. Nevertheless, various forms of
long-term contracts and other options (such
as direct acquisition of gas reserves or long-
term pre-purchase arrangements) are available
to provide an element of price stability,
while also minimizing downside risks to the
parties involved.
� Hedging is a strategy that is better suited to
managing short-term price risks. It is generally
implemented through the use of financial
instruments known as derivatives. Properly
applied, financial derivatives can provide
an efficient mechanism for transferring
risk. A concern has been raised that new
restrictions on derivatives trading under
the recently passed Dodd–Frank financial
reform legislation could have the unintended
consequence of reducing liquidity in natural
gas and other commodities markets, with
potentially adverse impacts on price stability
in those markets.
Conclusion
Recent assessments of the North American
natural gas resource base suggest that the
United States is well positioned to take
advantage of natural gas as a low-emitting,
domestic fuel that can be used throughout
the economy in a variety of efficient and
cost-effective applications. Realizing this
potential could provide significant economic,
environmental and energy security benefits
but requires that investors have confidence
in the ability to develop and deploy natural
gas resources at moderate and reasonably
stable prices. The Task Force believes that a
set of relatively modest but well-designed and
forward-looking policy initiatives could go a
long way toward building that confidence.
These initiatives should be combined with
continued efforts to better characterize
the domestic gas resource base; address
environmental concerns; develop improved
extraction technologies; and provide critical
pipeline, import and storage capabilities.
At a time when political and economic
conditions have paralyzed much of the national-
level energy policy debate, the fact that a
group as diverse as the Task Force could reach
consensus on these measures suggests that
here is at least one important area—natural
gas markets—where progress is well within
reach. Given how much could be at stake in
ensuring stable U.S. natural gas markets over
the next several decades, the opportunity is
one that should not be missed.
14 Task Force on Ensuring Stable Natural Gas Markets
IA. Overview
It is now widely recognized that the United States
has extraordinarily large natural gas resources.
Natural gas is a comparatively clean-burning fuel
that can be efficiently used for heat and power
generation in many contexts. It is also an important
chemical feedstock. Yet, despite these attractive
characteristics, natural gas has been perceived until
recently as a limited energy source that cannot
meet all of domestic demand. This has led to policy
debates over how and where the nation’s “limited”
supply is best applied. In addition, occasional
periods of high prices, especially over the last ten
years, have raised concerns over the economic risk
associated with investments and policies based on
expanded use of natural gas.
I .
INTRODUCTION
Task Force on Ensuring Stable Natural Gas Markets 15
CURRENT ESTIMATES SUGGEST THAT
IDENTIFIED U.S. GAS RESOURCES
ALONE COULD SUPPORT MORE
THAN 100 YEARS OF DEMAND AT
PRESENT LEVELS OF CONSUMPTION.
3 Obama, B. H. Address before a joint session of the Congress on the State of the Union, January 25, 2011. Retrieved from The Office of the Press Secretary, The White House: http://www.whitehouse.gov/the-press-office/2011/01/25/remarks-president-state-union-address
Starting in 2005, however, the demonstration of
technology to cost-effectively recover gas from
substantial North American shale gas resources
began to dramatically increase the economically
recoverable supply of natural gas. Indeed,
current estimates suggest that identified
U.S. gas resources alone could support more
than 100 years of demand at present levels of
consumption, assuming success in addressing
environmental challenges. This is good news
from multiple perspectives, since confidence in
the long-term adequacy of natural gas supplies
could greatly improve prospects for advancing
broadly held environmental, security and
economic goals.
The efficient use of natural gas can provide a
cleaner, low-carbon, low-cost alternative to the
use of other fossil fuels in the electric power
and industrial sectors. Notably, President
Obama, in his 2011 State of the Union address,
called for a new federal clean energy standard
for generating electricity that could be satisfied,
in part, by using natural gas.3 Gas can also
play a critical role in rebuilding a vigorous,
globally competitive manufacturing base here
in the United States. To make the most of
this potential, it will be necessary to address
concerns about long-term supply adequacy and
price stability that have been an impediment to
wider use of gas in the past.
Price stability is particularly important for
several sectors that purchase gas, such as for
industrial production, as a chemical feedstock,
and for electric power production. Frequent,
large price spikes can discourage investment
in new gas-based infrastructure (new
16 Task Force on Ensuring Stable Natural Gas Markets
THE TASK FORCE HAS
FOCUSED ON PRACTICAL
MEASURES THAT WOULD
PROMOTE THE MID-
TO LONG-TERM PRICE
STABILITY NEEDED TO
SUPPORT THE REQUISITE
CAPITAL INVESTMENTS
GOING FORWARD.
4 The Bipartisan Policy Center (BPC) is a non-profit organization that was established in 2007 by former Senate Majority Leaders Howard Baker, Tom Daschle, Bob Dole and George Mitchell to develop and promote solutions that can attract public support and political momentum in order to achieve real progress. The BPC acts as an incubator for policy efforts that engage top political figures, advocates, academics and business leaders in the art of principled compromise.
5 The American Clean Skies Foundation is a Washington, D.C. non-profit organization, created in 2007 to advance energy independence and a cleaner, low-carbon environment through expanded use of natural gas, renewable energy and efficiency.
manufacturing or power facilities) and/or cause
disruption in gas-reliant industries that have
international competitors who are not subject
to similar price variability. Local natural gas
distribution companies (LDCs) that provide gas
to residential, commercial and small industrial
gas users are also interested in better ways to
provide price stability to their customers.
In sum, with the prospect of a steady increase
in domestic natural gas resources (see e.g.,
Table 1), the possibility of increased gas use is
plainly attractive provided historic concerns on
price stability can be resolved. Thus, this Task
Force was largely focused on understanding
past sources of mid- to long-term gas price
variability, both to promote a more complete
and up-to-date understanding of the history and
future outlook for U.S. natural gas markets, and
to provide a basis for suggesting policies and
measures that would reduce price variability
and market instability going forward.
B. Structure of Task Force and Work Plan
The Task Force was jointly convened by the
Bipartisan Policy Center4 and the American
Clean Skies Foundation5 in March 2010.
The aim of the Task Force was to examine
historic causes of instability in natural gas
markets and to explore potential remedies.
Its membership—which includes natural gas
producers, transporters and suppliers as well
as gas consumers, independent experts, state
regulatory commissions and environmental
interests—was carefully selected to allow
for a full airing of the issues from multiple
perspectives (See Preface for a list of members).
During 2010, the Task Force held three daylong
workshops to review 11 commissioned papers
and policy briefs (see Appendix B). The Task
Force also held five working meetings in 2010
and 2011. As a result of this yearlong effort,
the Task Force adopted a set of findings and
recommendations for better managing price
variability in the future. Throughout, the Task
Force has focused on practical measures that
would promote the mid- to long-term price
stability needed to support the requisite capital
investments going forward—both in new gas
production capacity and in efficient new gas-
using infrastructure.
C. Report Structure
The body of this report is organized as follows:
Section II provides background on the role
and uses of natural gas in the U.S. economy
as a context for the practical and political
considerations behind the interest in gas use
and pricing. Section III discusses approaches
to improving mid- to long-term gas price
stability. Section IV offers conclusions and
recommendations and identifies next steps.
Task Force on Ensuring Stable Natural Gas Markets 17
18 Task Force on Ensuring Stable Natural Gas Markets
I I .
BACKGROUND ON NATURAL GAS MARKETS, USE AND SUPPLY
TA. Uses and Markets
To understand the past and future pricing of natural
gas, it is important to understand the role of gas in
the economy, how it is bought and sold, by whom,
and what affects these markets. Figure 2 shows that
natural gas is the second largest primary source of
energy in the United States, behind petroleum and
slightly ahead of coal.
Task Force on Ensuring Stable Natural Gas Markets 19
Moreover, natural gas is unique among the
energy sources shown in Figure 2 in that it
plays a major role in multiple, diverse sectors
of the economy. Figure 3 shows that coal is
almost exclusively used in the power sector,
petroleum is primarily used for transportation
and only secondarily as an energy source and
petrochemical feedstock in the industrial sector,
and hydro and nuclear power are used solely for
electricity generation. Natural gas, by contrast,
is used as a fuel in the residential, commercial,
power and industrial sectors, and as a chemical
feedstock. This diversity of end uses means that
the behavior of natural gas markets has a direct
and significant impact on many sectors of the
broader economy.
Because natural gas has been supply-
constrained at various times over the last few
decades, this diversity of end uses has also
created real or perceived competition between
sectors and/or customer classes for access
to gas supplies. Policymakers have debated
Figure 2. U.S. Energy Mix - 2010
U.S. Energy Consumption 201096.61 quadrillion Btu
Oil, 37.1Natural Gas, 23.2Coal, 20.5
Nuclear, 8.5Renewables, 7.2
7.2%
8.5%
20.5%
37.1%
23.1%
Source: U.S. Energy Information Administration. Annual Energy Outlook 2010.
20 Task Force on Ensuring Stable Natural Gas Markets
6 42 U.S.C. 8301 et seq. This Act restricted the construction of power plants using oil or natural gas as a primary fuel and encouraged the use of coal, nuclear energy and other fuels in the electric power sector. It also restricted the industrial use of oil and natural gas in large boilers.
what constitutes the “best” use of gas—as a
fuel for home heating, a chemical feedstock,
a source for power generation or in industrial
applications. At various times, government
policies have sought to limit—or prohibit—use
of gas by large industrial and power sector
users in order to prioritize or allocate gas use
to residential or other uses. Perhaps the most
extreme example was the 1978 Power Plant
and Industrial Fuel Use Act.6 Thus, uses of
natural gas have at times been subject to direct
government regulation in a way that generally
has not been applied to other fuels. These
interventions failed to recognize that limiting
potential markets inevitably had an impact of
exploration and production activity.
The sources and applications of different
fuels also affect their pricing. U.S. demand
for natural gas is supplied almost entirely
from North American producers. As a result,
prices are determined by North American
supply and demand. By contrast, 60 percent
of U.S. petroleum is imported (including from
Canada) and prices are determined by the
world petroleum market which the United
States does not control.
Their different applications also affect the way
that different fuels are purchased and priced.
Most coal transactions are wholesale transactions
between coal producers and large industrial and
power sector consumers. In addition, because
coal characteristics vary widely from one mine
to another, it was standard practice for many
years for power plants to be designed for a
specific type of coal. This meant plant operators
could purchase coal from a limited number of
mines or suppliers. As a result, both suppliers
and users benefited from long-term contracts
that could ensure, on the one hand, that the
plant would have a lifetime supply of the fuel
it required, and, on the other hand, that the
producer would have a long-term customer to
justify the cost of developing that supply. In
recent years, some coal-fired power plants have
introduced more flexibility in their coal supply
options. This has resulted in more flexible
contracting structures and reduced reliance on
long-term contracts in the coal industry (see
discussion in Section III.B).
Natural gas and petroleum products are more
standard commodities that have historically
traded in more liquid markets where consumers
can choose between suppliers based on market
conditions and other factors rather than being
limited by product characteristics. Changes
Figure 3. U.S. Energy Consumption by Sector - 2010
Nuclear
Renewable
Coal
Natural Gas
Oil
Feedstock
Feedstock
Residential Commercial Industrial Transportation Electric
Quadrillio
n B
tu
40
35
30
25
20
15
10
5
0
Source: U.S. Energy Information Administration. Annual Energy Outlook 2010.
Task Force on Ensuring Stable Natural Gas Markets 21
7 Note that power generation users are also exposed to gas price variability, and that the owners of power generation are typically not LDC’s.
8 Wellhead prices through 1994. Henry Hub prices from 1995 – 2010.
9 Energy Information Administration, U.S. Department of Energy, http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
in the price of crude oil are passed through
very directly to all customers; an increase in
the world oil price is quickly reflected at the
gasoline pump.
The majority of natural gas customers are
small residential, commercial and industrial
customers who purchase gas from regulated
local distribution companies (LDCs).7 The LDCs
purchase gas from producers and are required
by law to sell the gas to their customers at the
price they paid for it. This means LDC customers
will generally see any natural gas price increases
or decreases. However, LDCs use a variety of
physical and financial strategies to manage their
costs, and this often helps buffer the immediate
impact of short-term price movements. In
addition, the consumer gas bill is made up of
two parts: the cost of delivering or distributing
the gas, and the cost of the gas itself. The
LDC delivery charge is regulated by PUCs or
municipalities and tends to be relatively stable,
generally increasing at approximately the rate of
inflation over time. For these reasons, the price of
natural gas service to small consumers is typically
less variable than the underlying wholesale gas
price. Large natural gas consumers must manage
fuel costs themselves and are more directly
exposed to changes in wholesale prices.
Figure 4 shows U.S. natural gas prices from
1976 through the end of 2010.8 It shows a
period from the early 1980s to mid-1990s when
gas prices stayed roughly stable at around $2
per thousand cubic feet (mcf). Starting in 1996,
variability increases. In 2000, prices increased
sharply but then declined again in 2001. Price
spikes reappeared in 2005 and 2008, but prices
have since declined sharply and now remain in
the pre-2000 range.
This price trajectory, especially during the last
decade, explains recent concern about gas
price variability, particularly among large gas
Figure 4. U.S. Natural Gas Price 1976 to 2010 (Nominal dollars)9
$14
$12
$10
$8
$6
$4
$2
$0Jan
1976Jan
2009Jan
2006Jan
2003Jan
2000Jan
1997Jan
1994Jan1991
Jan1988
Jan1985
Jan1982
Jan1979
Source: U.S. Energy Information Administration.
22 Task Force on Ensuring Stable Natural Gas Markets
TODAY’S COMPETITIVE
NATURAL GAS MARKET
IS ONLY 17 YEARS OLD
AND THE MAJOR
SOURCES OF NATURAL
GAS HAVE CHANGED.
10 Much of this section is based on Price Instability in the U.S. Natural Gas Industry Historical Perspective and Overview, Navigant Consulting. See Appendix B.
11 FERC Order 636, known as the Restructuring Rule, was issued on April 8, 1992, and was designed to allow more efficient use of the interstate natural gas transmission system by fundamentally changing the way pipeline companies conduct business. Whereas previous orders had encouraged pipeline companies to provide transportation service on a nondiscriminatory basis, without favoring their own source of supply, Order 636 required interstate pipeline companies to unbundle, or separate, their sales and transportation services. The purpose of the unbundling provision was to ensure that the gas of other suppliers could receive the same quality of transportation services previously enjoyed by a pipeline company’s own gas sales. Unbundling increased competition among gas sellers and diminished the market power of pipeline companies.
12 That case, Phillips Petroleum v. State of Wisconsin, 347 U.S. 672 (1954), held that under the Natural Gas Act, the federal government has the authority to regulate prices charged by natural gas producers at the wellhead.
13 Mcf, a standard designation of a volume of natural gas, is 1000 standard cubic feet or approximately 1,031,000 British Thermal Units (Btu) of energy. As a point of reference, one gallon of gasoline contains approximately 132,000 Btus. Thus, 1 Mcf of natural gas is approximately equivalent in energy content to 8 gallons of gasoline.
consumers. There are two components to this
concern. First, the price of natural gas increased
dramatically during the last decade. Second,
price fluctuations have been pronounced,
with prices ranging from less than $4/mcf to
more than $12/mcf. At or below the middle
end of this range, the price of natural gas may
be attractive for investment in new gas-based
industrial or power facilities. However, such
investments are likely to appear too risky if
there is a chance that prices may suddenly rise
to and remain at the high end of the range. The
next section discusses the reasons behind this
historic price variability.
B. History and Sources of Price Variability
The U.S. natural gas industry has been in
existence at least since the 1920s.10 However,
today’s competitive natural gas market is
only 17 years old and the major sources of
natural gas have changed as well. Natural gas
was originally produced from associated (i.e.,
collocated) reservoirs as a by-product of oil
production. Early in the 20th century it was
simply burned off in flares (this is still common
practice in countries with no gas distribution
infrastructure). Eventually the gas was captured
for use and with the development of the natural
gas pipeline network after World War II, it
began to play an important role in the U.S.
energy system. Most gas was still “associated”
with oil production, though some “non-
associated” gas-only wells were developed in
conventional geological formations.
Until the Natural Gas Wellhead Decontrol
Act of 1989 (implemented in the 1990–
1991 time frame) and the Federal Energy
Regulatory Commission’s (FERC’s) Order No.
636 (issued in 1992, with implementation
in 1993),11 natural gas pricing was highly
regulated through a system of cost-based
wellhead pricing. This pricing system, which
was imposed in 1954 as the result of the U.S.
Supreme Court’s decision in the Phillips
case,12 led first to chronic shortages, then to
significant oversupply with radically varying
prices. During this period, the national ceiling
price for natural gas in interstate markets
was set by the Federal Power Commission
(the FPC was the predecessor to the FERC) at
$0.52/mcf.13 At the same time, prices in the
nonfederally regulated intrastate markets of
Texas and Louisiana were several times that,
approximately $2.50/mcf. Due to the low
interstate price, there was a disincentive to
produce and sell gas for the interstate market.
This led to gas shortages and required the FPC
to spend much of its time in administrative
curtailment proceedings to allocate scarce gas
supplies among markets. Nevertheless, some
areas of the country still experienced crippling
shortages—albeit at stable prices.
Task Force on Ensuring Stable Natural Gas Markets 23
THE POWER PLANT AND
INDUSTRIAL FUEL USE ACT
RESTRICTED THE CONSTRUCTION
OF POWER PLANTS USING OIL
OR NATURAL GAS AS A PRIMARY
FUEL AND ENCOURAGED THE USE
OF COAL, NUCLEAR ENERGY
AND OTHER FUELS IN THE ELECTRIC
POWER SECTOR.
14 In the Natural Gas Policy Act of 1978, 15 U.S.C.A. Sec. 3301, Section 107, deep gas is defined as natural gas that is produced from sources greater than 15,000 feet below the surface.
In 1976, the FPC attempted a limited remedy by
significantly raising the costbased ceiling, from
$0.52 to $1.42 per mcf. In 1978, Congress passed
the Natural Gas Policy Act of 1978 (NGPA). The
NGPA was part of a package of statutes designed
to reform energy regulation. Among other things,
the NGPA prescribed new, noncostbased prices
for new sources of natural gas, with the aim of
focusing economic incentives on the development
of new gas resources and particularly “deep gas.”14
Existing regulated sources of gas were essentially
frozen at the old, regulated price. As a result,
when the NGPA took full effect in 1979, the
natural gas industry was subject to 27 different
ceiling prices, ranging from approximately
40 cents to approximately $7/mcf (with some
categories being altogether deregulated over
time). It was thought that offering high prices for
new supply would stimulate new drilling, while
freezing most “old” gas at its old prices would
mitigate consumer impacts.
The Power Plant and Industrial Fuel Use Act
(FUA) was also passed in 1978 in response to
concerns over national energy security. The
FUA restricted the construction of power plants
using oil or natural gas as a primary fuel and
encouraged the use of coal, nuclear energy and
other fuels in the electric power sector. It also
restricted the industrial use of oil and natural
gas in large boilers.
High prices for new gas were successful
in bringing forth substantial new supplies
but because consuming markets had been
depressed by erratically high pipeline prices
and by statutory limitations on the use of
natural gas, the industry entered a long period
of oversupply and stable low prices. In 1987
the Fuel Use Act was repealed, allowing the
construction of large new gas facilities.
As of 1990, a parallel system of open-access
pipeline transportation had evolved under
FERC Order No. 436. Congress had also passed
the Wellhead Decontrol Act, which fully
deregulated all wellhead natural gas prices.
Accomplishing these changes without major
price spikes was possible because the industry
had built up a relatively large backlog of excess
supply capability. Then, in 1992, FERC issued
Order No. 636, essentially completing the
transition to an open market. Under Order 636,
interstate pipelines were relieved of their
marketing role entirely—now consumers would
purchase natural gas directly from producers,
paying separately for the pipeline transportation
and storage services necessary to deliver the
gas. By establishing a direct link between
ultimate buyers and the original suppliers of
gas, FERC allowed (and still allows) supply and
demand to interact directly and quickly.
The regulated period prior to 1990 established
a historical context for gas users in which
gas markets were characterized by mostly
stable prices but limited supply and extensive
government intervention. This period
concluded with the transition to a much more
open market for natural gas, one that still
exists today and that set the stage for the price
record over the last decade.
24 Task Force on Ensuring Stable Natural Gas Markets
BY 2000, ALL OF THE
AVAILABLE PRODUCTION
WAS BEING CONSUMED AND
THERE WAS DEMAND FOR
ADDITIONAL SUPPLY THAT
WAS NOT BEING MET.
15 Henry Hub, Louisiana, is a major production area delivery point in the gas industry. The NYMEX Natural Gas Futures contract uses the Henry Hub price as the reference price.
16 Gas deliverability is the maximum production rate that can be delivered to the market.
For the most part, the 1990 through 2000
period saw continued stable prices and strong
supply. Prices at the nation’s largest pipeline
junction (known as the Henry Hub15 and located
in Louisiana) started somewhat below $2/mcf as
decontrol began and settled in at approximately
$2/mcf until 1996 when the market began to
show a seasonal pricing response to high winter
heating loads. Prices spiked briefly to $5.50/mcf
during an unusually cold winter, then settled
back down to levels that hovered around $2/mcf.
Figure 5 shows producing capacity in the
lower 48 states, the actual quantity of gas
produced, and the wellhead price. In the first
period, the gap between productive capacity
or “deliverability16” and actual production
represents the “excess” production capacity of
the “gas bubble” period and the continued low
and relatively stable prices that accompanied it.
However, with the end of preferential pricing
for nonconventional gas production, productive
capacity began to decline. At the same time, the
repeal of the Fuel Use Act allowed gas use for
large industrials and power generation to
increase. Natural gas consumption for electric
generation rose from 2.6 Tcf in 1988 to 5.7
Tcf in 2002, an increase of about 119 percent.
Natural gas consumption for industrial
processing rose from 6.4 Tcf in 1988 to 7.6 Tcf
in 2002, an increase of almost 19 percent.
The combination of declining productive
capacity and increasing demand spelled the
end of the gas bubble. By 2000, there was
no excess production capacity— all of the
available production was being consumed
and there was demand for additional supply
that was not being met. On a pure supply and
demand basis, this resulted in a sharp spike
in gas prices in 2000. While prices declined
in 2001, largely as the result of an economic
Productive Capacity Gas Production Price
$0
$2
$4
$6
$8
$10
$12
$14
$16
30
35
40
45
50
55
60
65
Jan 9
5Ju
l 95
Jan 9
6Ju
l 96
Jan 9
7Ju
l 97
Jan 9
8Ju
l 98
Jan 9
9Ju
l 99
Jan 0
0Ju
l 00
Jan 0
1Ju
l 01
Jan 0
2Ju
l 02
Jan 0
3Ju
l 03
Jan 0
4Ju
l 04
Jan 0
5Ju
l 05
Jan 0
6Ju
l 06
Jan 0
7Ju
l 07
Jan 0
8Ju
l 08
Jan 0
9Ju
l 09
Jan 1
0Ju
l 10
Jan 1
1Ju
l 11
Jan 1
2Ju
l 12
Jan 1
3Ju
l 13
Jan 1
4Ju
l 14
Low
er 48 P
roduct
ion (Bcf
d)
Henry
Hub P
rice
($/M
MBtu
)
Figure 5. U.S. Natural Gas Balance and Pricing
Source: ICF International.
Task Force on Ensuring Stable Natural Gas Markets 25
17 U.S. Department of Energy, Energy Information Administration, “U.S. Natural Gas Wellhead Price,” EIA Data Navigator. Accessed 2/14/2011. http://tonto.eia.gov/dnav/ng/hist/n9190us3m.htm.
downturn that reduced demand, tightening
supplies relative to demand produced a gradual
return to higher prices in the first half of the
decade. In 2005, hurricanes Katrina and Rita
shut down production in much of the Gulf of
Mexico and even some onshore production,
resulting in another, higher price spike. In
early 2008, prices for natural gas, as for other
energy commodities, increased sharply due, in
part, to large financial inflows to gas and other
commodity and derivative markets. By mid-
2008, however, prices had begun to fall and
soon dropped sharply.17
Figure 6 shows spot prices for gas, oil and coal
since 1995, indexed to 2000 levels. The figure
shows that gas markets have experienced some
notable price spikes that are different from the
other fuels, but that overall, the price trends are
not that different. The exceptions for gas are
the 2000-2001 spike, discussed above, and the
spike in 2005 due to hurricane activity. On the
other hand, in 2008, all three fuels experienced
a price spike that is not well explained except
as a response to broader financial and
commodity trends.
As already noted, lower gas prices starting
in 2008 were partly the result of reduced
demand due to the economic downturn. More
important for long-term price stability, the
period of higher prices in the preceding decade
had triggered renewed interest in developing
non-conventional gas resources. This resulted
in advances in hydraulic fracturing technology
that, starting in 2005, began to be reflected
in increasing productive capacity (see Figure
5). These trends are forecast to continue (see
discussion in Section III.A.i.). Clearly, advances
in exploration and production technology will
affect gas production economics in North
America for decades to come.
COALBGSD Coal Price Crude Oil WTI Spot Henry Hub Natural Gas Spot
Jan 9
5
Jul 95
Jan 9
6
Jul 96
Jan 9
7
Jul 97
Jan 9
8
Jul 98
Jan 9
9
Jul 99
Jan 0
0
Jul 00
Jan 0
1
Jul 01
Jan 0
2
Jul 02
Jan 0
3
Jul 03
Jan 0
4
Jul 04
Jan 0
5
Jul 05
Jan 0
6
Jul 06
Jan 0
7
Jul 07
Jan 0
8
Jul 08
Jan 0
9
Jul 09
Jan 1
0
0
1
2
3
4
5
6
Pric
e In
dex
(Jan
-200
0 =
1)
Figure 6. Indexed Fuel Prices - 1995 to 2010
GAS MARKETS HAVE EXPERIENCED
SOME NOTABLE PRICE SPIKES THAT
ARE DIFFERENT FROM THE OTHER
FUELS, BUT OVERALL, THE PRICE
TRENDS ARE NOT THAT DIFFERENT.
Source: ICF International analysis of U.S. Energy Information Administration data.
26 Task Force on Ensuring Stable Natural Gas Markets
18 See also AGA Foundation 2003 report reviewing volatility. The report also pinpointed the importance of having an adequate storage cushion to buffer short term changes in demand in supply constrained markets.
This review of recent gas market trends
suggests several conclusions:
� Natural gas markets have been competitive
and open for less than 20 years.
� The periods of highest gas prices in the last
10 years have resulted from identifiable
circumstances, such as changes in regulation,
hurricane disruptions, market momentum and
broader trends in energy commodity markets.18
� The broader increase in gas prices in the
first part of the last decade resulted from
increasing demand relative to supply, at a
time when supply was effectively flat. This
price increase also reflected a return to
unregulated market pricing.
� Periods of higher gas prices have prompted
the development of new gas resources,
the application of improved technology and
increased supply.
C. Impact of Gas Pricing and Variability
on the Economy
It should be clear that the price of natural gas
has important economic implications for both
large and small consumers. In addition, two
different forms of price movements affect
gas market participants in two fundamentally
different ways:
1. Investment/planning price variability. Planning
price variability refers to long-term uncertainty
about energy price levels that influence
investment planning. For example, both natural
gas producers and large consumers in today's
environment are unsure whether prices in the
next five to seven years will remain at recent
levels—that is, around $4 mcf—or rise to levels
$14
$12
$10
$8
$6
$4
$2
$0
Natural Gas Futures Prices NYMEX(Nominal USD per MMBtu)
Jan 08
Jun 08
Nov 08
Apr 0
9
Sep 09
Feb 10
Jul 1
0
Dec 10
May
11
Oct 1
1
Mar 12
Aug 12
Jan 13
Jun 13
Nov 13
Apr 1
4
Sep 14
Feb 15
Jul 1
5
Dec 15
May
16
Oct 1
6
Mar 17
Aug 17
Jan 18
Jun 18
Nov 18
Apr 1
9
Sep 19
Feb 20
Jul 2
0
Dec 20
Historical HH 1/8/07 1/7/08 1/7/09 1/7/10 1/7/11
Figure 7. Natural Gas Futures Prices - 2008 to 2010
Source: New York Mercantile Exchange.
ADVERSE IMPACTS ARISING
FROM PRICE VARIABILITY
ARE RELATED PRINCIPALLY
TO THE UNCERTAINTY AND
RISK THAT ARE CREATED
BY LONGER-TERM PRICE
FLUCTUATIONS RATHER THAN
DAY-TO-DAY MOVEMENTS.
Task Force on Ensuring Stable Natural Gas Markets 27
19 In its deliberations, the Task Force examined available reports, including Natural Gas and Energy Price Volatility (Oak Ridge National Laboratory 2003), as well as various papers commissioned specifically by the Task Force including Price Instability in the U.S. Natural Gas Industry Historical Perspective and Overview (Navigant 2010).
20 That said, the ability of industrial customers to recover fluctuations in day-to-day gas prices can be limited by competition and the structure of their own industries.
seen in 2007 and 2008. Currently, this seems
unlikely, based on the forward price curve
to 2015, which reflects gas futures contracts
(Figure 7). This uncertainty can discourage
investment by both producers and consumers.
2. Trading price variability. Trading price
variability reflects short-term (day-to-day or
month-to-month) price fluctuations that
influence short-term energy purchasing and
hedging strategies.19
Adverse impacts arising from price variability
are related principally to the uncertainty and risk
that are created by longer-term price fluctuations
rather than day-to-day movements.20
i. Impact on Small Consumers
Gas bills for small customers are driven by three
factors: the cost of natural gas, the amount of
natural gas used each month and the cost of
getting the gas from the producer to the customer.
Firm service customers, who account for almost
all residential deliveries and about 63 percent of
total commercial deliveries, purchase natural gas
at regulated distribution rates from LDCs. These
distribution rates cover the cost of safely getting
the gas from the producer to the customer. The
firm customer is also charged for the cost of gas
purchased by the LDC for the customer. The LDC
is not allowed to mark up the price of gas. The
customer pays what the LDC pays—no more and
no less. The cost of gas delivered to the city gate,
which includes transportation and storage, is
usually the largest part of the customer’s bill. This
means that a firm service customer will usually
have a very predictable regulated distribution
charge but far less predictable charges for the
gas itself. Of course the other big factor in the
customer’s bill is the amount of gas used. Colder
weather means higher bills. Many residential
consumers react only when they receive an
unexpectedly high gas bill. In addition, most
residential and small commercial customers do
not differentiate between a high bill that is due
to an increase in the price of gas rather than a
consumption increase (e.g., due to weather).
Price variability mainly impacts household
budgets for residential customers. For
commercial customers, the impact may affect
profitability. In many cases, the impact of
weather on gas consumption and prices can
result in fluctuations in gas bills of 50 percent
or more from one season to the next, much
more than typical variability in actual prices.
28 Task Force on Ensuring Stable Natural Gas Markets
COMPETITION WITH
IMPORTS IS A SIGNIFICANT
RISK FOR DOMESTIC
MANUFACTURERS WITH A
STRONG DEPENDENCE ON
LOCAL ENERGY RESOURCES.
That said, a long-term increase in price will
affect consumers and may lead to a response
from utility regulators. Some LDCs have
developed programs to help insulate their
customers as much as possible from short-
term price changes in wholesale markets.
However, while LDCs have a variety of physical
and financial options to do this, they are also
limited by their regulators and may be subject
to retroactive review of their actions. This issue
is discussed further in Section III.C.ii.
ii. Impact on Large Consumers
Industrial customers (including power
generators) can be much less insulated from
changes in energy prices than either residential
or commercial customers. LDC sales account
for only a small percentage of the natural gas
supplied to industry (about 17 percent in 2001).
The remainder is delivered by the LDC via
gas transportation services or directly from
pipelines. Industrial customers purchase the
natural gas commodity either at market prices,
or hedged through a natural gas marketer. In
both cases, industrial customers are directly
exposed to market prices. If the customer does
not have any hedged supply, the customer will
be purchasing at market prices. Even if gas
supplies are hedged, the industrial customer
typically will value the natural gas at the
opportunity cost reflected by the market price.
For these customers, changes in gas prices
can put severe pressure on profit margins and
the competitiveness of their products. Some
manufacturers can pass higher costs on to their
customers while manufacturers in other markets
may have less ability to do so. The situation for
many domestic producers has become more
detrimental with the globalization of many
markets, leading them to compete with foreign
producers who may not be subject to the same
fuel and feedstock price pressures.
Competition with imports is a significant risk
for domestic manufacturers with a strong
dependence on local energy resources. Although
energy costs make up a relatively small share
of production costs in many industries, some
industries are particularly energy-intensive.
These include many of the basic commodity
industries such as iron and steel; stone, clay and
glass; and the basic chemical industries. The
cost of natural gas is particularly important for
industries that use gas for feedstock as well
as fuel. For example, ammonia producers use
natural gas as a feedstock and a fuel. Since
ammonia is a globally traded commodity,
increases in U.S. gas prices can have, and have
Natural gas price movements are particularly important to the petrochemical industry where natural gas
is used as a feedstock to produce diverse products including fertilizer, plastics and other products. For
some companies, the natural gas feedstock can constitute more than 70 percent of the cost of production.
Moreover, with global markets for many – if not most – of these products, gas price movements in North America
that do not correlate with gas prices in other countries can be extremely disruptive. On the other hand, in some
countries, these products are produced from petroleum feedstocks, which can be higher in price.
Recent developments in the production of shale gas can have positive impacts on feedstock uses as well as fuel
uses. The production of natural gas liquids (NGLs) in the United States has increased significantly in conjunction with
unconventional gas production growth. Book reserves of NGLs have grown even faster to the point where the United
States has become a net exporter of NGLs and propane and will likely remain so until or unless additional domestic
capacity to use the products is built.
Task Force on Ensuring Stable Natural Gas Markets 29
21 Frank, C. Graves and Steven H. Levine, The Brattle Group, Managing Natural Gas Price Volatility: Principles and Practices Across the Industry. See Appendix B.
had, an enormous impact on the competitiveness
and viability of the U.S. industry. The production
of chemicals such as ethylene from natural gas
liquids is a related industry that is also sensitive
to natural gas availability and pricing. Gas price
variability has a huge effect on the viability of
these industries and the workers and consumers
that depend on them.21
Fuel and feedstock prices also affect siting
decisions as manufacturers consider where
to invest in new facilities. There is increasing
pressure to locate new facilities in areas or
countries with low and stable energy prices,
although other considerations, such as labor,
infrastructure, and transportation costs,
obviously also remain important factors. In
the case of natural gas, there are countries
with ample, underutilized resources where
gas prices are much lower than in the United
States. In some countries, the gas resource is
owned and managed by the government, which
is in a position to establish long-term pricing
arrangements. Although this mitigates the
price risk in one way, it creates susceptibility to
political risk in the event of a change in policy
or regime. Nevertheless, a recent surge in the
development of chemical and manufacturing
capacity in foreign countries with large, low-
priced gas resources illustrates the potential
impact and risk to the U.S. economy.
In the power sector, there is by comparison,
limited risk of competitive imports from
outside the United States. Nevertheless, there
is competition between generators that rely
on gas and those powered by other fuels.
Since the electricity product is itself a uniform
commodity (a kilowatt-hour is indistinguishable
from any another kilowatt-hour, regardless of
how it was generated), competition between
different fuel sources in this sector is largely
based on price, although other factors (such as
environmental attributes) may also come into
play. Gas-based generators compete with coal,
nuclear and renewable generators for a share
of the baseload electricity market. At low gas
prices, gas is competitive against all of these
alternatives, but higher prices may put gas out
of the baseload market. Meanwhile, uncertainty
about future prices prevents utilities and
developers from investing in new gas-fired
capacity even though it can be among the most
efficient and least polluting options.
Expectations about future gas prices can
also have important implications for the
competitiveness of renewable energy resources
because natural gas capacity is often looked
to as the backup source to provide firm
capacity for intermittent resources like wind
and solar. However, there are questions
related to the financing of the gas resource
and delivery capacity, just as there are on the
electric side. That is, how will gas delivery
and generating capacity that is used only
intermittently be paid for and by whom if
there are no baseload customers? From the
standpoint of gas producers, there is also
concern that the increased demand for gas-
fired “balancing” service as a result of expanded
renewable capacity will be less than the
demand lost as a result of replacing baseload
gas generation with renewable production.
When prices are high, power sector and
industrial users of gas may lose market share,
resulting in reduced gas consumption. This
response is useful to maintain the balance of
supply and demand but may entail lost output
and jobs in the affected sectors. The balancing
of demand with supply is critical to increased
use of North American gas resources, both to
provide stable pricing to consumers and to
provide a stable demand outlook for producers.
As the industry has gained experience in
producing unconventional gas, production
cost curves have shifted downward. Recent
experience with shale gas production provides
considerable evidence of this trend, given
the steady growth of the estimated recoverable
resource base at $6/Mcf or less.22Despite
recent positive supply developments, many
large consumers remain cautious about
30 Task Force on Ensuring Stable Natural Gas Markets
Task Force on Ensuring Stable Natural Gas Markets 31
DESPITE RECENT POSITIVE SUPPLY
DEVELOPMENTS, MANY
LARGE CONSUMERS REMAIN
CAUTIOUS ABOUT INVESTING IN
NEW GAS-CONSUMING FACILITIES
DUE TO UNCERTAINTY OVER MID-
TO LONG-TERM GAS PRICES.
22 See e.g., MIT Energy Initiative, the Future of Natural Gas, an Interdisciplinary MIT Study, Interim Report, Executive Summary, June 2010, p. XXI; ICF International Compass Publication, Summer, 2010, 2010 Natural Gas Market Review, prepared by ICF International for the Ontario Energy Board, August 20, 2010
investing in new gas-consuming facilities due
to uncertainty over mid- to long-term gas
prices. At the same time, many gas producers
are cautious about continued investment in
production due to uncertainty about future
demand for their product and about
the potential for a sustained low gas price
environment.
iii. Impact on Energy Production and Delivery Companies
Sharp and unpredicted or misunderstood
movements in gas prices—up or down—
create additional uncertainty in the planning
process for producers as well as consumers,
making the capital budgeting process more
difficult. The economics of a decision to
expand investment in infrastructure, or to
spend resources in an attempt to develop
a new market area such as distributed
generation (DG), gas cooling or natural gas
vehicles are made much more uncertain.
Planning for DG infrastructure becomes
even more complex because of volatility in
electricity prices.
The primary risk to producers is the longer-
term cycling of gas prices that is generated by
“boom-bust” investment patterns, variations
in economic activity and pipeline capacity
constraints that can limit the ability to move
gas out of a production region. For gas
producers, variability and price uncertainty
raise the hurdle rates needed to justify a
drilling program. As a result, the long-term
expected price of gas is increased because of
the “risk premium” arising from uncertainty
about future prices.
32 Task Force on Ensuring Stable Natural Gas Markets
B
I I I .
APPROACHES TO IMPROVING MID- TO LONG-TERM PRICE STABILITY
Based on the historical context and market trends
identified in Section II, this section discusses
policies and other changes related to natural gas
markets that could improve mid- to long-term
price stability.
Task Force on Ensuring Stable Natural Gas Markets 33
THE EXPANSION OF GAS SHALE
PRODUCTION ALREADY APPEARS
TO BE HAVING A DAMPENING
EFFECT ON PRICE VARIABILITY.
A. Supply and Infrastructure
The preceding historical discussion noted that
natural gas prices are primarily determined
by the North American market and that both
supply and demand trends have a direct impact
on gas pricing. The foregoing strongly suggests
that one approach to moderating natural gas
prices over the mid- to long-term would be to
promote expanded capacity for producing and
delivering natural gas.
The lack of significant excess domestic production
capacity in the last decade made gas commodity
prices sensitive to short-term changes in supply
and demand, and in the short run, to the
availability of gas storage.23 As one would expect
in any commodity market, prices have responded
when supply is tight and demand is strong. A
further factor influencing the short-term volatility
of gas prices is the availability of sufficient
pipeline capacity from production areas,
transport hubs and storage facilities.
The expansion of gas shale production already
appears to be having a dampening effect on
price variability. Again, see Figure 7 on forward
curves to 2015. These developments and other
trends in infrastructure investment that may
contribute to less variable gas prices over the
mid- to long term are discussed below.
i. Shale and the New Gas Supply Paradigm
Section II discussed the dramatic change in
supply forecasts that resulted from new shale
gas production technology starting in the middle
of the last decade. Although there has been
much discussion of the implications of shale
gas, it may be that the full impacts have yet to
23 American Gas Foundation. Natural Gas and Energy Price Volatility. Chapter 3: Outlook for Future Natural Gas Price Volatility. Page 3-13.
34 Task Force on Ensuring Stable Natural Gas Markets
24 U.S. DOE, Office of Fossil Fuels and National Energy Technology Laboratory, Modern Shale Gas Development in the United States, a Primer. Prepared by Groundwater Protection Council (Oklahoma) and ALL Consulting. Washington, DC, 2009.
be understood. Clearly, a significant increase in
available U.S. natural gas resources, assuming
it leads to rising production, will have a
moderating effect on gas prices and variability.
While shale formations were long known
to contain substantial quantities of gas, the
formations are not porous like conventional
oil and gas formations, so that when drilled,
the gas cannot flow freely to the well. Rather,
drilling must be coupled with hydraulic
fracturing—a process of using high pressure
liquids to create cracks in the shale to allow the
gas to flow. This technology, shown in Figure 8,
has recently been combined with the practice
of horizontal drilling to dramatically increase
the amount of gas that can be recovered.
In the 1980s, producers began experimenting
with large-scale hydraulic fracturing in the area
around Fort Worth, Texas, in the geological play
known as the Barnett Shale. Fracturing was first
used in the Barnett in 1986; the first Barnett
horizontal well was drilled in 1992. Through
continued improvements in the techniques and
technology of hydraulic fracturing, development
of the Barnett Shale accelerated and caught
the attention of the industry. Since then, the
science of shale gas extraction has matured into
a sophisticated process involving horizontal
drilling and sequenced, multi-stage hydraulic
fracturing technologies. The techniques
pioneered in the Barnett have spread rapidly to
shales in other areas.24
Groundwater Aquifers
Additional steel casingand cement to protectgroundwater
Protectivesteel casing
Shale Fractures
MunicipalWater Well:< 1,000 ft.
PrivateWell
Not to Scale
Approximate distancefrom surface: 8,000 feet
Pumper
FuidStorage Tank
Sand TruckBlender
Truck
Fracturescreated by highpressure fluid
Figure 8. Diagram of Hydraulic Fracturing Process
THE SCIENCE OF SHALE GAS
EXTRACTION HAS MATURED
INTO A SOPHISTICATED
PROCESS INVOLVING
HORIZONTAL DRILLING AND
SEQUENCED, MULTI-STAGE
HYDRAULIC FRACTURING
TECHNOLOGIES.
Task Force on Ensuring Stable Natural Gas Markets 35
Despite these advances, the U.S. EIA’s Annual
Energy Outlook in 2000 estimated shale
resources at only 3.7 Tcf and projected that the
future contribution of shale to domestic supply
would be modest (Figure 9).
Even as late as the 2005 Annual Energy Outlook,
the full scope of the shale revolution had not yet
been recognized. By then, conventional resources
were seen as declining and LNG imports were
expected to be the next large incremental source
of natural gas supply to meet growing demand
(Figure 10).
Between 2005 and 2010, shale gas development
expanded rapidly. In addition to the Barnett,
producers began intensively developing plays in
the Woodford, north of the Barnett in Texas and
Oklahoma; the Fayetteville in Arkansas; and the
Haynesville in Louisiana/East Texas. During this
time development also began in the Marcellus
Shale of the eastern United States. In the 2011
Annual Energy Outlook, the domestic supply
picture has changed dramatically (Figure 11).
Changes in the forecast for future unconventional
and shale production are also matched by
revisions in the estimates of recoverable shale
reserves. Table 1 shows the rapid increase in
these estimates over the last ten years.
The size of the U.S. shale resource base is
only one aspect of its new-found importance
to the domestic supply outlook for natural
gas. Another is the widely distributed nature
of that resource base. Table 1 shows that
25 ICF International, 2010 Natural Gas Market Review, prepared for the Ontario Energy Board, August 2010, p. 48.
0
5
10
15
20
25
30
1990 1995 2000 2005 2010 2015 2020
Natural Gas Production,1990-2020
Gas Shales Coalbed Methane Tight Sands Conventional
Trillio
n C
ubic
Feet
History Projections
Sources: History: Advanced Resources International, Inc. (ARI). Projections: U.S. Energy Information Administration. Annual Energy Outlook 2000.
Figure 9. Natural Gas Production, 1998 to 2020
0
5
10
15
20
25
30
Growth in Alaskan Production Growth in LNG Imports
Growth in Non-associated Unconventional Base Production (all sources)
Trillio
n C
ubic
Feet
Major Sources of Incremental Natural Gas Supply,2003-2025 (trillion cubic feet)
2005 2010 2015 2020 2025
Figure 10. U.S. Energy Information Administration Supply Forecast - 2005
Source: U.S. Energy Information Administration. Staff’s Forecast of Natural Gas Prices. Annual Energy Outlook 2005.
Table 1. Published Estimates of U.S. Lower 48 Recoverable Shale Gas (Tcf )
USGS (Various years)
EIA 2000 NPC 2003 EIA 2007 ICF 2008 PGC 2009 ICF 201025
85 3.7 35 125 385 616 1,395
Source: ICF International. 2010 Natural Gas Market Review. Prepared for the Ontario Energy Board. August 2010. Page 48.
36 Task Force on Ensuring Stable Natural Gas Markets
26 ICF International, p. 48.
27 MIT Energy Initiative, the Future of Natural Gas, an Interdisciplinary MIT Study, Interim Report. Cambridge, Massachusetts: Massachusetts Institute of Technology, 2010.
28 MIT Energy Initiative, p. 11.
shale is ubiquitous, with major production
opportunities located in Texas (Barnett and
Woodford), Arkansas (Fayetteville), Louisiana
(Haynesville), and the Appalachians (Marcellus).
Shale is also found in Illinois, Michigan and
other areas farther west and north. In short, the
distribution of shale resources is close to the
major eastern U.S. consuming markets and to
the pipeline systems serving those markets.
The Marcellus shale, extending from Virginia
in the south to New York to the north, is the
largest shale resource, conservatively estimated
to be approximately 700 Tcf.26
In late 2010, the MIT Energy Initiative published
its Interim Report, The Future of Natural Gas,
re-examining the supply outlook.27 One of the
major findings of the study was that consensus
estimates of the size of the total U.S. resource
base (including Alaska) had increased to about
2,100 Tcf, with much of the increase coming
from the addition of over 600 Tcf of shale gas
in the lower 48 states.
While estimates of supply have increased,
the cost of producing shale gas has declined
as more wells have been drilled and as new
techniques have been developed and field
tested. The MIT study estimated that between
250 and 300 Tcf of shale gas can be produced
at prices below $8/MMBtu (in 2007 dollars).28
More recently, ICF International estimated that
almost 1,500 Tcf are available at $8/MMBtu,
while 500 Tcf are available at $4/MMBtu
(Figure 13). In either case, the opportunity for
substantially expanded domestic gas production
is large. The MIT report summarized the
situation as follows:
History Projections
0
1990 2000 2009 2020 2035
U.S. dry gas production (trillion cubic feet per year)
5
10
15
20
25
30
11%
14%
28%
20%
9%
8% 2% 9%
Shale gas
Tight gas
Non-associated onshore
Non-associated offshore
Coalbed methane Alaska
Net imports
Associated with oil
1%
45%
8%
8%
22%
1%
7%
7%
Source: Richard Newell, Administrator, U.S. Energy Information Administrator, Energy Outlook 2011. Presentation, Washington, DC: Dec. 16, 2010.
Figure 11. U.S. Energy Information Administration U.S. Dry Gas Production Forecast - 2011
Task Force on Ensuring Stable Natural Gas Markets 37
“The large inventory of undrilled shale
acreage, together with the relatively high
initial productivity of many shale wells,
allows a rapid production response to any
particular drilling effort. However, this
responsiveness will change over time as
the plays mature, and significant drilling
effort is required just to maintain stable
production against relatively high inherent
production decline rates.”29
While the development of shale gas offers the
potential to make significant new supplies of
natural gas available at moderate prices, large
uncertainties remain regarding the future
development of these resources.
A first question is to what extent current
resource assessments accurately capture the
actual economically recoverable resource base.
Our understanding of key technical aspects of
this resource base is still evolving and questions
remain in a number of areas: whether productive
areas are representative of an entire play; whether
and to what extent “sweet spots” may be skewing
resource assessments; uncertainty about the
trajectory of well production decline; and the
effect of technology and technological innovation.
A second category of uncertainty concerns
the cost of producing and delivering shale
gas; the availability of pipeline and processing
infrastructure in proximity to the resource
29 MIT Energy Initiative, p. 13.
Rio GrandeEmbayment
MaverickSub-Basin
MarfaBasin
PermianBasin
Palo DuroBasin
AnadarkoBasin
RatonBasin
San JuanBasin
PiceanceBasin
GreaterGreen River
Basin
MontanaThrustBelt Williston
Basin
Forest CityBasin
Paradox Basin
Uinta Basin
Cherokee Platform
Arkoma Basin Black WarriorBasin
Valley andRidge Province
IllinoisBasin
MichiganBasin
AppalachianBasin
Ardmore Basin
Ft. WorthBasin
Texas-Lousiana-Mississippi Salt Basin
EagleFord
Barnett
Bend
Pierre
CodyGammon
Lewis
Mancos
Hermosa
Hilliard- Baxter-
Mancos
WoodfordFayetteville
Excello-Mulky New
Albany
Antrim
Hanesville
Floyd-Neal
Chattanooga
Conasauga
Devonian(Ohio)
Marcellus
Utica
Pearsall-Eagle Ford
Barnett-Woodford
Woodford-Caney
Shale Gas Plays
Shallowest / Youngest
Deepest / Oldest
Stacked Plays
Basins
Figure 12. Shale Gas Basins in North America
Source: National Energy Board of Canada.
38 Task Force on Ensuring Stable Natural Gas Markets
A TYPICAL FRACTURING
OPERATION CONSUMES 2
TO 4 MILLION GALLONS OF
WATER. THERE IS CONCERN
ABOUT THE POTENTIAL FOR
AN EXCESSIVE DRAIN ON
WATER RESOURCES IN AREAS
WHERE LARGE NUMBERS OF
WELLS ARE BEING DRILLED.
30 MIT Energy Initiative, p. 15.
base; and well drilling costs, which are a large
technological and cost component in the
development of shale gas resources.
ii. Environmental Impacts Associated with Shale Gas
A third and last (but by no means least
important) source of uncertainty centers on the
environmental risks associated with shale gas
development and their implications for public
acceptance of increased shale gas production in
different areas of the country. The MIT report
summarizes the environmental concerns, which
include the risk of shallow freshwater aquifer
contamination from fracture fluids; the risk of
surface water contamination from inadequate
care in the disposal of drilling fluids and
produced water; the effects of fracturing water
requirements on local water supplies; and the
impact of intensive drilling on communities,
especially as more drilling occurs in densely
settled areas of the eastern United States.
While more than 20,000 shale wells have been
drilled in the past 10 years with little adverse
environmental impact, environmental risks
and concerns are likely to become increasingly
important if and when production activities
expand substantially beyond current levels.
These risks and concerns will have to be
carefully monitored and managed to avoid
adverse impacts and to ensure that communities
remain willing to accept shale gas development
based on confidence that appropriate safeguards
for the protection of the environment and the
public are in place.30 (See Text Box)
At the same time, the industry and its regulators
must continue to devote attention to the
environmental issues associated with hydraulic
fracturing and water use, and take the steps
necessary to avoid problems that could
undermine public confidence in the industry’s
ability to access this resource base in an
environmentally safe and a prudent manner.
0
2
4
6
8
10
12
14
0 500 1,000 1,500 2,000 2,500 3,000 3,500
Tota
l Cost
of Deve
lopm
ent at W
ellhead
2007 U
.S. $ p
er M
MBtu
Dry Gas Resource (Trillion Cubic Feet)
CBM Tight Conventional Shale Total
Source: ICF International.
Figure 13. U.S. Natural Gas Resource Cost Curves by Type
31 United States Environmental Protection Agency, Office of Research and Development, “Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources,” EPA/600/D-11/001/February 2011/www.epa.gov/research. Accessed February 8th, 2011. http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/HFStudyPlanDraft_SAB_020711.pdf.
32 American Petroluem Institute Press Release. December 14, 2010. http://api-ec.api.org/Newsroom/chemical-disclosure.cfm.
Environmental Impacts of Shale Gas Production
With the growth of shale gas production, and
particularly the move to produce in areas outside
of the traditional gas-producing areas, such as in
the Marcellus shale, there has been an increasing focus on
the environmental impacts of shale gas production. While the
debate is often centered on shale gas production in general
and the hydraulic fracturing process in particular, many of
the issues are not specific to either and must be addressed
for any type of natural gas production. Nevertheless, the
rapid growth of shale gas production and its high visibility
require that these issues be addressed and resolved. State
and federal regulators have already begun new initiatives to
review and update their evaluations of these issues.
Hydraulic fracturing: There are concerns that the hydraulic
fracturing process itself could allow either fracturing fluids
or gas to migrate into drinking water resources. Fracturing
typically takes place at a depth of 6,000 to 10,000 feet,
while drinking water tables are typically less than 1,000 feet
deep; thus the fracturing process per se is unlikely to impact
fresh water aquifers. There are concerns however, over other
facets of shale gas production (e.g., faulty well casings),
which may have affected drinking water. In 2011, the U.S.
Environmental Protection Agency (EPA) will begin a two-
year study to review the extent to which hydraulic fracturing
poses a threat to safe drinking water supplies.31
Well casing and maintenance: While there is little evidence
that leaks from hydraulic fracturing have affected ground water,
there have been documented incidents where fracturing fluids
or methane have impacted surface and well water supplies due
to improper well casing. While this risk is not unique to shale
gas production, the migration of shale gas production into new
areas is generating more interest in this issue.
Water consumption for fracturing: A typical fracturing
operation consumes 2 to 4 million gallons of water. While
this is less than many industrial processes, less than typical
consumption to water a golf course, and much less than the
water consumed by a power plant, there is concern about
the potential for an excessive drain on water resources in
areas where large numbers of wells are being drilled. Among
other approaches, producers are investigating the use of
water recycling to reduce consumption.
Management and disposal of fracturing fluids and produced
water: The fracturing fluid is mostly water but does contain
some chemicals. After the fracturing job, most of the water
is discharged from the well, possibly along with water from
the producing formation. In addition to the chemicals in
the fracturing fluid, the produced water may include other
organic and inorganic contaminants as well as naturally
occurring radioactive material. These millions of gallons of
gallons of water must be properly managed and disposed
of. Some water treatment facilities may not be capable
of treating this volume or type of discharge. In addition,
fracturing contractors have heretofore refused to disclose
the exact composition of some fracturing fluids, creating
additional concerns. Several industry organizations have
recently agreed to voluntarily disclose the content of
fracking fluids through an online database.32
General emissions and disruption: Natural gas production
involves the operation of trucks and other heavy equipment
as well as the possible construction of new roads, gathering
lines and drill pads in remote areas. This produces a range of
potential impacts, including air pollution, noise, risk of spills,
changes in land use, potential disruption of wildlife and
general disruption of the area around the production area.
Methane leakage: Natural gas or methane is itself a potent
greenhouse gas. Thus an important aspect of the natural
gas industry’s environmental performance involves efforts
to reduce and minimize methane leakage in all phases of
extraction, transportation, storage and delivery.
EPA analysis of the available data demonstrates that
switching from another fossil fuel to natural gas reduces
emissions of carbon dioxide and of air pollutants that are
associated with direct adverse public health impacts, such
as particulate matter. Ongoing efforts by industry, working in
conjunction with EPA, to implement best practices to reduce
all forms of harmful emissions and to update estimated
emission factors for transmission and distribution facilities
are needed, as are improved data concerning emissions
from production facilities. Importantly, confidence in these
efforts must be maintained or the benefits of natural gas
usage could be called into question.
Task Force on Ensuring Stable Natural Gas Markets 39
mption for frar
wa
powe
drain on produ
s P
ga
t
ga
e h
pac
er
fr
no
off
th
ha
e
w
yd
ra
o
a
n
redu
te estim
nd dis
mproved da
uction f
err
on
tha
d
n
e
c
e
m
fra
4 m
rial
e a
is c
ource
efforts must be maintained or ther
on
Whi
in
ar,
st
eve
nd
ed
dy
io
a
o
dr
at
t
tu
rs
a
a
P
e
d
Man
dence in t
b
e
as
oc
tion
ucti
arti
nd
ion
cti
dd
a
ev
: T
it
te
p
ng
t
e
ff
m
on
s
e
e
a
e
r r
s
eaa
er
ti
le
tio
um
for r
nu
duce
nsump
as
e
as
ocu
ion
ctio
rtic
m
n.
on
re
re
lu
er
lff
o
e
e
ac
fe
g
e
r
t
d
h
im
as
m
ore
ctur
llio
oces
d muc
rn abo
from
ing emission
production facilities Importantl
and
are
are
inc
ga
e
ro
to
gas
g
ss
lat
da
fra
g
to
al
e
e
e
fa
w
t
ga
ea
co
n c
tha
wa
a po
sive d
are being
of
ons
onfidenc
ned or ther b
usage ld b
40 Task Force on Ensuring Stable Natural Gas Markets
INDUSTRY AND
GOVERNMENT WILL NEED
TO WORK TOGETHER
TO PROACTIVELY ADDRESS
ENVIRONMENTAL AND PUBLIC
SAFETY CONCERNS.
33 In recent years, gas production from conventional wells in the Western Canadian Sedimentary Basis (WCSB) has declined. The WCSB is the primary source of gas production in Canada for domestic consumption and export to the United States. While the development of unconventional gas including shale gas in British Columbia may offset further declines, increases in Canadian consumption for domestic use (e.g. power generation and the development of oil production from oil sand projects) are likely to result in less gas being available for net export from Canada to the United States. See ICF International, Inc. “2010 Natural Gas Market Overview,” August 20, 2010, p. 8.
In summary, the consensus is that North
American natural gas resources are much
larger than previously understood and can
supply an expanded gas market. Moreover, with
current technology, the cost of producing the
gas will be lower than previously thought. This
will allow the broader use of gas in efficient
applications for power and transportation. At
the same time, more abundant supply has the
potential to moderate future fluctuations in
gas prices. However, to assure access to this
resource base, industry and government will
need to work together to proactively address
environmental and public safety concerns,
including public safety concerns that are
unrelated to hydraulic fracturing per se. In
particular, the Task Force is mindful that recent,
well-publicized pipeline accidents have drawn
attention to integrity of the existing natural gas
transportation and distribution infrastructure.
While outside the scope of issues considered
by the Task Force, attention to public safety
obviously needs to remain a paramount
concern for the industry and its regulators
going forward.
Figure 14 shows sources of U.S. natural gas
supply since 1985 and projected through 2030.
U.S. gas consumption has totaled about 20–23
Tcf per year since the 1990s. The figure also
shows changes in gas production over time.
Onshore conventional production has supplied
less than half of consumption since 1990 and
is flat or declining. Offshore production in the
Gulf of Mexico was the next largest source to
come into the mix, but has also been declining
and may be even less available going forward
due to limits on offshore production. Canadian
pipeline imports have been an important supply
component since the 1990s, but are projected
to decline as low-price U.S. shale gas depresses
demand for Canadian gas.33 Finally, non-
Task Force on Ensuring Stable Natural Gas Markets 41
34 Includes information from “LNG, Globalization, and Price Volatility,” Kenneth B Medlock III. See Appendix B.
35 NARUC, Liquefied Natural Gas: An Overview of Issues for State Public Utility Commissions. Washington, D.C.; National Association of Regulatory Utility Commissioners, 2005. In testimony before the Senate Energy and Resources Committee on July 10, 2003, Alan Greenspan urged expansion of LNG import capability: “Without the flexibility such facilities will impart, imbalances in supply and demand must inevitably engender price volatility.”
conventional production of tight gas and coal-
bed methane has been the last piece added to the
supply to boost total U.S. annual production up
to approximately 23 Tcf in recent years.
With offshore and Canadian production
declining and prices rising, there has been
more financial support for nonconventional
production and more interest in LNG imports.
High prices also supported the development
of shale gas production techniques over the
last decade. The currently understood and
projected shale gas resource has allowed the
United States to project a significant increase
in economically recoverable gas resources for
the first time in the last 15 years. And for the
first time since the 1990s, it now appears that
deliverability (i.e. available production) could
be adequate to meet increasing gas demand,
meaning that the United States will no longer
be in the tight supply/demand regime that
has historically made natural gas markets
vulnerable to price instability.
iii. Imports: Liquefied Natural Gas34
While the natural gas market is primarily
a North American market, the potential to
import significant amounts of gas from other
countries and continents has been available
for many years and, in recent years, has grown
significantly. This is especially true since the
price of gas in some exporting countries (i.e.,
Qatar) is extremely low due to low production
costs and limited domestic demand.
The first modern liquefied natural gas (LNG)
receiving terminal in the United States entered
service in Boston in 1971. In response to the
supply shortages of the 1970s, three more
terminals were constructed by 1982, all on
the Gulf and East Coasts. For the next 20
years however, LNG imports were minimal.
Largely because of prevailing low gas prices,
two of the terminals were mothballed for a
long period. After 2000, greater variability in
U.S. gas prices brought a renewed interest in
importing LNG. By 2005, FERC had received
applications for 55 new LNG import terminals
(or expansions at existing ones).35 Today there
are seven operating LNG import terminals in
the eastern United States, plus two additional
terminals that serve U.S. markets from Baja
Mexico and Maritimes Canada. Total LNG
import capacity is about 15 Bcf per day within
a market that is approximately 65 Bcf per day.
0
5
10
15
20
25
30
35
1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
U.S
. Natu
ral Gas
Supply
(TCF)
Shale
Other Non-Conventional
Lower-48 LNG
Net Pipeline Imports
Offshore Gulf
Onshore Conventional
Figure 14. Evolution of U.S. Natural Gas Supply
Source: U.S. Energy Information Administration, Annual Energy Outlook 2011, Reference Case, Preliminary Release, December 16, 2011.
42 Task Force on Ensuring Stable Natural Gas Markets
36 The growth in shale gas production in various geographic locations has changed historical relationships between regional gas prices. In particular, Marcellus gas production in Pennsylvania and West Virginia has compressed price differentials between the Gulf Coast and eastern United States.
37 See Cheniere Marketing, LLC application, pursuant to DOE Delegation Order No. 00-002.00I (Nov. 10, 2009). Also, Freeport LNG filed an LNG export application with the U.S. Department of Energy on December 17, 2010. The application, available under FE Docket No. 10-160-LNG, contemplates the export of 225 million metric tons of LNG over a 25-year period to countries with which the United States currently has entered into free trade agreements or may enter free trade agreements in the future.
Thus, based on existing import capacity, LNG
could theoretically meet 20 percent of current
market requirements.
LNG terminals are necessarily limited to
coastal sites. While many terminals have been
proposed for locations along the East Coast
and a few terminals have been proposed on the
West Coast, virtually all of the new terminals
that have actually been constructed are located
on the Gulf Coast. There are two primary
reasons for this. Proposed East and West
Coast projects have met with intense public
opposition. Opponents have been successful in
blocking these terminals from getting approvals
at the state level, even where FERC has
approved the applications. The Coastal Zone
Management Act affords state government
effective veto power over LNG terminal siting.
Gulf Coast communities have been far less
hostile to these facilities, largely, it is believed,
because the region is already accustomed to
extensive petrochemical development.
Another reason for locating LNG terminals on
the Gulf Coast is that pipeline takeaway capacity
is much more robust in this region. From the
Gulf, importers can reach virtually the entire
eastern half of the United States. In addition, the
gas market along the Gulf is large and liquid,
and price discovery is relatively straightforward
with Henry Hub being nearby. The attraction of
East Coast sites, especially north of the Carolinas,
has been that gas prices have historically been
higher there than in the Gulf. At the same time,
pipeline takeaway capacity is more limited
on the East Coast; in addition these markets
are comparatively less liquid and local prices
are more susceptible to the influence of LNG
deliveries. Nevertheless, large price differentials
relative to the Henry Hub have historically
made LNG a more attractive investment in the
northeastern United States.36
At today’s prevailing lower prices, however,
and with the current outlook for gas supply
and prices, it is not likely that new LNG import
terminals will be added to the current U.S.
fleet—with the possible exception of lower
volume offshore terminals. In fact, in the face
of growing U.S. gas supplies, some owners of
LNG impact terminals have applied for export
authorization and intend to install liquefaction
facilities. Even if new export terminals are built,
however, the extent of exports is likely to be
modest for at least the next decade (i.e., less
than 5 percent of the market).37
Access to Resources
Natural gas resources exist in almost every part of the
United States and in coastal areas. Efforts to develop
these resources, as with other natural resources, are
subject to tensions between development and preservation of
the natural environment. While gas development is under way
in many parts of the United States, there are also large areas
in which development is limited or prohibited including parks,
other national lands, the Atlantic and Pacific coastlines, and
parts of the Gulf of Mexico. The identification of a new resource
often triggers a struggle over whether it should be developed
in light of environmental or other land-use concerns. The venue
for resolving the question depends on the specific location
and jurisdiction in question and there are often overlapping
authorities involved. The public policy and regulatory processes
should carefully weigh the value of gas production against
protection of the environment and public health to ensure that
a proper balance is struck.
Task Force on Ensuring Stable Natural Gas Markets 43
IN THE FACE OF GROWING U.S.
GAS SUPPLIES, SOME OWNERS
OF LNG IMPACT TERMINALS
HAVE APPLIED FOR EXPORT
AUTHORIZATION AND INTEND TO
INSTALL LIQUEFACTION FACILITIES.
38 Includes information from “Natural Gas Storage: A Discussion of the Value of Storage Gas, Recent Developments, and Implications for Public Policy”, ICF International. Prepared for the Task Force on Ensuring Stable Natural Gas, July 2010. See Appendix B.
In principle, LNG imports can help moderate gas
price volatility and undoubtedly they have had
this effect in some instances. However, ongoing
LNG sales to the United States have been modest
in recent years given the historic spread between
U.S. prices and gas prices elsewhere in the
world. Europe, Japan, South Korea, China and
India—the major markets for LNG—pay oil-
linked prices for LNG. U.S. prices are set by
gas-on-gas competition and are consistently
below world LNG prices. The American market
is only likely to attract global LNG supplies when
prices are high (i.e., in winter) and in high value
locations (the Northeast). In general, current
policies and FERC’s efficient regulation of LNG
facility siting have allowed LNG capacity to
evolve with market needs.
iv. Storage38
Gas storage facilities allow gas produced in
one time period to be used at a later date. Gas
wells operate optimally when they produce at
steady rates. Gas demand, on the other hand,
is highly seasonal due to winter heating load
and summer electric generating demand. On
top of the seasonal cycle, there are weekly and
daily use patterns that do not match well with
production and pipeline deliveries. Storage
capability is expressed in two ways: the amount
of gas that can be stored (reservoir capacity is
typically measured in million British Thermal
Units (MMBtu)) and the capacity to deliver a
given quantity of gas to the market in a given
timeframe, otherwise known as “deliverability”
and typically measured in MMBtu per day.
Thus, early in the development of the gas
pipeline system, gas storage was designed
to manage swings in demand by storing gas
in the ground when demand was light and
releasing it when demand increased.
Following the deregulation of wholesale gas
prices, storage has also become a physical way
of hedging future price risks for utilities and
producers; likewise, it is also provides a financial
tool for price arbitrage by marketers and
suppliers as seasonal demand varies. Both the
physical and financial aspects of storage have
can be used as tools to promote price stability.
There are three types of underground storage:
depleted reservoir, aquifer and salt cavern
storage. In the United States, depleted natural
gas or oil fields provide about 85 percent of
working gas storage capacity and 70 percent
of deliverability because of their widespread
availability. Converting a field from production
to storage takes advantage of existing wells,
gathering systems and pipeline connections.
Most of this storage is cycled once a year
to meet seasonal demand: injecting gas in
summer and withdrawing in winter.
44 Task Force on Ensuring Stable Natural Gas Markets
GROWTH IN THE AMOUNT
OF STORAGE AVAILABLE
TO THE MARKET IS AN
IMPORTANT CONTRIBUTOR
TO MORE STABLE AND
COMPETITIVE GAS PRICES.
39 U.S. Department of Energy, Energy Information Administration.
40 EIA, Underground Natural Gas Storage Capacity. http://www.eia.gov/dnav/ng/ng_stor_cap_dcu_nus_a.htm.
Salt caverns work on a shorter cycle, providing
very high withdrawal and injection rates for
their working gas capacity through two or more
cycles per year. Salt cavern storage accounts for
about 5 percent of working gas storage capacity
but 17 percent of deliverability. The large
majority of salt cavern storage facilities are
located along the Gulf Coast, where there are
large bedded salt deposits.
Figure 15 shows the location of U.S. gas storage
facilities. Some regions of the country do not have
suitable underground storage sites including
the East Coast, New England and the Southeast.
Between 2000 and 2006, new storage capacity
increased on average by 46 Bcf per year reaching
8.4 Tcf of total capacity. Since then capacity
additions have averaged 109 Bcf per year.
Between 2000 and 2010, approximately 700
Bcf of new working gas storage capacity has
been constructed. In 2009, total U.S. storage
capacity reached 8.7 Tcf and working gas storage
capacity reached 4.3 Tcf39 or nearly 20 percent
of the annual market.40 Thus, by 2009, levels of
storage capacity had reached a new high, both in
absolute and percentage terms.
Investment in additional storage is expected to
continue. Several factors have contributed to
this growth in storage capacity:
� Regulatory changes have encouraged
more development at market-based rates,
Depleted FieldsSalt CavernsAquifers
Consuming West
Consuming East
Producing
Figure 15. U.S. Underground Storage Locations
Source: U.S. Energy Information Administration. GasTran Geographic Information System Underground Storage Database.
Task Force on Ensuring Stable Natural Gas Markets 45
41 Pursuant to the implementation of Section 312 of the Energy Policy Act of 2005, FERC issued Order 678. Under this order, guidance was issued as to how FERC will evaluate applications to charge market-based rates when storage providers do not demonstrate that they lack market power. FERC adopted this rule to reduce natural gas price volatility and encourage the development of natural gas storage capacity in the United States.
thus increasing the potential return to
storage developers.41
� Growth in natural gas power generation has
increased the need for high deliverability
storage to meet swings in gas load.
� Actual and anticipated growth in LNG
imports has led to demand for storage to
manage LNG delivery patterns.
� Historic price variability through 2008
increased the value of storage to a broader
array of market participants, including
utilities that need to manage seasonal and
daily price risk; marketers and financial
traders who want to benefit from price
variability through physical arbitrage; and
suppliers that are interested in maximizing
opportunities created by price swings.
� An increase in liquidity and deliverability
at gas market hubs has reduced reliance on
long-haul pipeline capacity to meet winter load
and further increased the need for market area
storage as supplements to gas supply.
The role of storage is likely to become more
prominent as overall gas consumption expands.
The growth in gas-fired power generation
increases the need for storage to manage
seasonal and weather-related swings in fuel
requirements. Similarly, as more renewable
generation capacity is installed, reliance on gas
units for firming power is likely to increase
demand for gas storage capacity.
Storage plays a prominent role in gas system
operating reliability and increasingly in gas
pricing. Utilities’ use of storage to meet demand
swings allows them to buy gas at lower off-peak
prices and deliver it to customers at those prices
during the winter peak season. Storage has also
become a major tool in gas market operations for
hedging risk and arbitrage. As storage capacity
continues to grow, storage operations will tend to
moderate gas prices.
Storage also plays a critical role in managing
and mitigating gas price movements that result
from increases in consumption or tightness
in gas supply availability. Thus, growth in the
amount of storage available to the market—
now at a historic high and still growing—is
an important contributor to more stable and
competitive gas prices.
46 Task Force on Ensuring Stable Natural Gas Markets
PIPELINE OWNERS AND
THE FERC HAVE BEEN
RESPONSIVE TO THE NEED
FOR ADDITIONAL PIPELINE
CAPACITY TO BRING
NEW GAS TO MARKET.
v. Pipelines
The North American natural gas market is
integrated through an extensive interstate
pipeline network that connects gas supply
markets with gas consuming markets. Price
signals flow across this network and markets
adjust based on the availability of pipeline
capacity and prices.
In principle, gas prices between two markets
reflect the cost of transportation between the two
markets. The difference—called the “basis”—
also reflects local market supply and demand
balances. Therefore, on the margin, the basis can
fluctuate to reflect the relative value of gas in the
markets at any point in time. It also fluctuates as
a function of pipeline capacity when, for instance,
demand for gas is strong in a downstream
market and there is inadequate capacity to
supply all the gas demanded. Basis “blowouts,”
where the price skyrockets, have been seen
in markets where there are severe capacity
limitations due to sharp short-term increases in
demand (e.g., due to an unforeseen cold snap)–
prominent examples of this phenomenon have
occurred in New York and New England.
Basis blowouts can also happen in supply
markets, but in the opposite direction. If
there is inadequate pipeline capacity from a
producing region relative to production, sellers
will compete for space by cutting prices and
wellhead prices can collapse. Recurring or
persistent basis blowouts signal the need for
new pipeline capacity.
Most investment in gas pipeline capacity in
recent years has been driven by supply growth.
With increased production from shale and in
from the Rocky Mountain region, the United
States has seen major new pipeline expansions
in recent years to bring this gas to market.
Several major pipeline segments have been
added since 2006:
� Centerpoint, Carthage to Perryville (Texas/
Louisiana), 1.2 Bcf/d
� Rockies Express (Wyoming to Ohio), 1.8 Bcf/d
� Gulf South (Louisiana, Mississippi,
Alabama), 560 MMcf/d
� Fayetteville Expansion (approved by FERC,
2009, Arkansas/Mississippi), 2.0 Bcf/d
� Ruby Pipeline (approved by FERC, 2010,
Wyoming/California), 1.5 Bcf/d
While gas pipeline capacity is nominally
abundant in the Marcellus shale production
region, significant new capacity is needed
to connect and flow the gas into the system.
Table 2 lists announced pipeline projects in
the Northeast, mostly to serve Marcellus
shale production.
FERC has been active in reviewing pipeline
proposals and approving new pipelines and
pipeline expansions. Over the last five years,
FERC has approved approximately 68 Bcf per
day of new pipeline capacity and 9,000 miles
Task Force on Ensuring Stable Natural Gas Markets 47
Table 2. Gas Pipeline Expansions in the Northeast
Pipeline - Expansion Name AreaCapacity (MMcfd)
Planned In Service
Dominion Transmission - Dominion Hub II Leidy PA to Albany NY 20 Nov-10
Dominion Transmission - Dominion Hub III Clarington OH Reciepts 224 Nov-10
Dominion Transmission - Rural ValleyLine 19/20 NW PA to Oakford PA 57 Nov-10
Dominion Transmission - Appalachia Gateway West Virginia to Oakford PA 484 Sep-12
Dominion Transmission - Marcellus 404 Project West Virginia 300 Nov-12
Texas Eastern - TIME III Oakford PA to Transco 60 Nov-11
Texas Eastern - TEMAX Clarington to Transco 395 Nov-10
Texas Eastern - TEAM 2012 “Interconnects OH, WV, PA” 190 Nov-12
Spectra -TETCO - Algonquin - NJ-NY Expansion Linden NJ to Staten Island NY 800 Nov-13
National Fuel - West to East Phase 1 Overbeck PA to Leidy 200 Nov-11
National Fuel - West to East Phase 2 Overbeck PA to Leidy 300 Nov-12
National Fuel - Lamont Compression Lamont PA 40 May-10
National Fuel/Empire - Tioga County Extension Tioga PA to Corning NY 200 Sep-11
National Fuel - Line N Expansion Alnong Western PA border 150 Sep-11
National Fuel - Appalachian Latteral Clarington OH to Overbeck PA 625 Nov-11
Tennessee Gas Pipeline - Line 300 Line Upgrade Line 300 across northern PA 350 Nov-11
Tennessee Gas Pipeline - Northeast Supply Diversification New copression station near Niagara NY 50 Nov-12
Tennessee Gas Pipeline - MLN Project (Marcellus-Leidy-Niagara) New copression station near Niagara NY 118 Nov-12
Tennessee Gas Pipeline - Northeast Upgrade Project Line 300 to Interconnects with NJ Pipelines 636 Nov-13
Columbia Gas Transmission - Line 1570/Marcellus Shale Northwest Pennsylvania 150 Jun-10
Columbia Gas Transmission - Line 1570/Line K Replacment Northwest Pennsylvania TBD 2011?
Columbia Gas Transmission - Columbia Penn Corridor Phase 1 Waynesburg PA to Delmont PA 101 Mar-10
Columbia Gas Transmission - Columbia Penn Corridor Phase 2 Leidy PA to Corning NY 500 Jun-12
Williams Transcontinetal - Northeast Supply ProjectSt195 SE PA to Rockway Deliv Lateral - National Grid NYC
625 Nov-13
Williams/Domminon - Keystone Connector REX Clarington OH to Transco St195 SE PA 1000 Nov-13
Iroquois Gas Transmission - Metro Express Waddington or Brookfield to Market areas 300 Nov-12
Iroquois Gas Transmission - NYMarc Sussex NJ to Pleasant Valley NY 1000 Nov-14
Inergy Midstream - Marc I Hub Line Bedford PA (Tenn) to Columbia Co PA (Transco) 550 Oct-11
Inergy Midstream - North-South ProjectTioga NY (Millenium) to Bradford PA (Tenn/Transco)
325 Nov-11
Laser Marcellus Midstream - Marcellus Gathering Susquehanna PA to Millenium (NY) 60 2011
Williams Partners - Susquehanna Gathering(Cabot Oil) Susquehanna PA to Luzerne PA (Transco) 250 Jun-11
EQT Midstream - EQT Gathering Expansion WV and West PA 300-900 2013
EQT Midstream - Marcellus Eastern Access Hub Braxton WV and Upshur WV TBD TBD
Dominion Transmission - Marcellus Gathering Enhancement with Appalachia Gateway 50 Sep-12
PVR Midstream - AMI Gathering “Lycoming PA, Tioga PA, and Bradford PA” 700 Nov-10
Source: ICF International compilation of public sources.
48 Task Force on Ensuring Stable Natural Gas Markets
42 ICF calculations from Approved Pipeline Projects, FERC website, http://www.ferc.gov/industries/gas/indus-act/pipelines/approved-projects.asp.
of new pipeline construction.42 Not all of this
capacity has been constructed. Nevertheless,
pipeline owners and the FERC have been
responsive to the need for additional pipeline
capacity to bring new gas to market.
B. New Approaches to Contracting
In addition to expanding natural gas production
capacity and the infrastructure necessary for
timely delivery, new contract arrangements can
facilitate a more stable horizon for gas prices. For
example, contracts that fix the terms for delivery
of gas over several years, even with agreed price
adjustments, may give producers and consumers
greater certainty in planning their businesses.
In turn, the adoption of similar arrangements by
other large producers and consumers could, over
time, lead to greater overall price stability.
Other commercial arrangements, including
greater use of physical and financial hedging
(see Section C), may also moderate the
potential for price variability—for both
producers and consumers.
The structure of gas purchase contracts
has changed over the years, along with the
regulation and structure of the market. The
search for future contracting alternatives
should be informed by this experience as well
as by a clear understanding of what can be
achieved through the contracting process.
i. Common Contract Terms
Buyers and sellers of natural gas (and other
energy commodities) often enter into contracts
to define the parameters of the transaction.
Major terms typically include:
� Term – the length of the contract.
� Volume – how much gas can or must be
purchased. This may include a “base” volume
and optional or “swing” amount or both. It
can affect price stability to a degree, but the
degree may be dependent upon the pricing
terms of the base and swing. Base volumes
combined with pricing terms provide a level
of revenue certainty to the seller and a level of
fixed obligations to the buyer.
� Price – can be fixed but is often based on a
formula such as indexing to a standard gas or
other energy price.
� Delivery Location – the point(s) at which title
to the gas transfers from seller to buyer.
� Re-openers – provisions that allow the contract
to be renegotiated if certain conditions are met.
This can also affect price stability to a degree.
� Others – contract terms that deal with credit,
default, force majeure, arbitration, etc.
While there is no inherent limitation on the
terms that can be negotiated between parties,
there is a tendency for parties to gravitate
toward contract structures that are common
within the industry. This is not surprising
since contracts that deviate significantly from
industry norms can present risks that the
parties may generally regard as excessive.
THE TASK FORCE
BELIEVES THAT GREATER
AVAILABILITY AND USE OF
LONG-TERM CONTRACTS
WILL TEND TO PROVIDE
GREATER MARKET STABILITY.
Task Force on Ensuring Stable Natural Gas Markets 49
43 The one exception may be historical coal prices. However, tying the price of natural gas inputs to another index may reduce the correlation of input and output price returns for a company, thereby increasing net income volatility. And the diversification of volatility could mean that idiosyncratic factors in other markets can affect the price paid for natural gas.
Pricing terms and contract length are arguably
the most important elements of any commodity
purchase contract, at least from an economic
perspective. It is sometimes asserted that price
stability can be achieved by requiring producers
to offer a long-term, fixed price, variable volume
contract—that is a contract that would allow
the buyer to purchase as much or as little gas
as desired at an absolute fixed price for a long
period of time (effectively granting the buyer a
no-cost option to purchase gas). However, such
contracts have never been common in the gas
industry, or for that matter in most commodity
markets, because they represent an unbearable
risk for producers (in effect, they place the
entire burden of pricing and market risk on
the producer). Instead, so as to share the risks
inherent in purchasing this commodity over an
extended period, long-term purchase contracts
are more likely to index prices to market
indicators.43 As discussed elsewhere, the Task
Force believes that greater availability and use
of such contracts, whether indexed or not, will
tend to provide greater market stability. This is
because the parameters of future price swings
are bracketed by the contract and thus can be
better factored into planning by both parties
(e.g., through separate hedging arrangements).
ii. History of Long-term Gas Contracts
Prior to the restructuring of the natural gas
industry, there was little scope for direct
producer–consumer contracting in the natural
gas market. Pipeline operators purchased gas
from producers and resold the gas to LDCs
or end-use customers on a bundled basis.
Moreover, in order to issue a Certificate of
Public Convenience and Necessity for an
interstate pipeline (as required by the Natural
Gas Act of 1938), FERC required that the
pipeline operator demonstrate sufficient gas
supply to justify construction. To meet this
requirement, pipeline operators (not end users)
generally entered into long-term contracts to
purchase gas, which they then used to meet
FERC’s certificate requirement.
These contracts contained a variety of pricing
provisions based on delivery locations,
customer classes and other terms. These
provisions, however, did not exist in a vacuum.
In 1954, the U.S. Supreme Court decided a
landmark case involving Phillips Petroleum.
As noted above, the Court ruled that under
the Natural Gas Act, the federal government
could regulate the prices charged by natural
gas producers when selling gas at the wellhead.
From that point until passage of the Natural
Gas Wellhead Decontrol Act of 1989, the price
paid under gas purchase contracts was almost
exclusively determined by regulation.
50 Task Force on Ensuring Stable Natural Gas Markets
WHILE NATURAL GAS
CONTRACTS HAVE OFTEN
EXTENDED OVER (RELATIVELY)
LONG PERIODS OF TIME,
THEY HAVE GENERALLY NOT
FEATURED FIXED PRICES AND
HAVE INCLUDED A VARIETY
OF OTHER PROVISIONS
THAT CREATED LIABILITIES
FOR PURCHASERS.
44 See e.g. National Association of Regulatory Utility Commissioners. Resolution on Long-Term Contracting. Adopted by the NARUC on November 16, 2005. http://www.naruc.org/Resolutions/GAS-1Long-TermContracting.pdf. In its resolution, the National Association of Regulatory Utility Commissioners (NARUC), urges state regulators to: “Recognize the need for additional gas infrastructure to accommodate future gas demand, and moderate the volatility of natural gas prices; Consider long term contracting as a potentially appropriate ingredient in a gas utility’s portfolio strategy; Encourage gas utilities to develop long-term strategies for capacity and supply contracts to access new and expanded natural gas and LNG supply sources; Not discourage long-term transportation and storage contracts when a specific record merits encouragement; and Consider pre-approval of long-term contracts.”
Few if any of the long-term contracts of this
period were “fixed price” contracts. Pricing
provisions referenced the regulatory structure
of the time and also contained provisions,
such as “favored nations” clauses, that assured
a producer that the price received would be
commensurate with the price received by other
producers in the area. In other instances, the
price might be indexed to distillate oil prices.
In addition to pricing terms, most of these
contracts also contained “take or pay”
provisions that assured a minimum revenue
stream to the seller of the gas. As discussed
later, these “take or pay provisions” created
significant liabilities for gas purchasers when
the underlying gas market changed in the
wake of restructuring.
In addition, other customers, most notably
independent merchant power producers,
developed contract practices that generally
incorporated long-term horizons. Financial
backers of new electric power plants often
required developers to demonstrate that
the project had obtained a reliable source
of gas supply and the preferred method for
making this demonstration was to enter
into a long-term supply contract. These
contracts often contained pricing mechanisms
indexed to an alternative fuel, such as fuel
oil, which influenced the competitiveness of
the electricity generated at the facility. The
contracts often also included “take or pay
terms” similar to pipeline gas supply contracts.
Just as with pipeline gas supply contracts,
the rigidity of these contracts created some
liability issues as changes occurred in market
supply and demand conditions and in the
regulatory structure.
In sum, while natural gas contracts have often
extended over (relatively) long periods of time,
they have generally not featured fixed prices and
have included a variety of other provisions that
created liabilities for purchasers. For example,
if oil prices increased, the indexed gas price
might rise above the otherwise prevailing price
but the buyer would be committed to continue
purchasing a fixed amount of gas at the indexed
price for the remaining life of the contract.
Because of these liabilities and as restructuring
created a more liquid gas commodity market
that allowed participants to enter and exit
commodity positions easily and at relatively
low cost, industry practice shifted toward
shorter contracts.
iii. Renewed Interest in Long-term Gas Contracts
In recent years, gas market participants,
regulators and other stakeholders have once
again given attention to the appropriate role
of long-term contracts in gas markets. At least
some of this attention has been prompted by
the opportunity for consumers to change their
risk profiles by adding long-term contracts for
natural gas to their gas requisition portfolio.44
The Task Force believes that this renewed
interest in longer-term contracts is a positive
development. Such contracts can provide a
degree of price stability, either through the use
of fixed prices or pricing formulas that allocate
or share the impact of unexpected changes
Task Force on Ensuring Stable Natural Gas Markets 51
WITH A PORTION OF THE OVERALL
PORTFOLIO STABILIZED, BUYERS
AND SELLERS HAVE A GREATER
ABILITY TO MAKE INVESTMENT
DECISIONS AND INVEST CAPITAL IN
LONG-LIVED FACILITIES.
45 Examples include Devon Petroleum v. Pittsfield Cogeneration Action No. 040 1 – 10854, IN THE COURT OF QUEEN’S BENCH OF ALBERTA JUDICIAL DISTRICT OF CALGARY.
46 Schwartz, Alan (1992a), “Legal Contract Theory and Incomplete Information,” in Werin, Lars and Wijkander, Hans (eds), Contract Economics, Oxford, Blackwell, and Schwartz, Alan (1992b), ‘Relational Contracts in the Courts: An Analysis of Incomplete Agreements and Judicial Strategies’, 21 Journal of Legal Studies, 271-318.
in price levels and can be a useful tool in a
diversified portfolio. With a portion of the
overall portfolio stabilized, buyers and sellers
have a greater ability to make investment
decisions and invest capital in long-lived
facilities. However, it is important to recognize
that “long-term” typically does not mean “fixed
price” and probably implies a variety of other
contractual obligations. Some of the parameters
of such contracts are discussed below.
Long-term Contracts as a Tool in a
Dynamic Portfolio
The Task Force views long-term contracts
as a tool, and not a panacea for promoting
greater price stability in natural gas markets.
Indeed, history has shown that overreliance
on fixed-price long-term contracts that do
not reflect changing market dynamics can
create a separate source of market instability
and impose unwanted liabilities on market
participants. During the restructuring of the
gas market that occurred between 1985 and
1995, large “take or pay” liabilities developed.
These created major commercial issues and
had to be resolved in order to establish a more
open market and trading environment.
Similarly, a number of independent power
producers and developers of cogeneration
projects that were designated as Qualified
Facilities (QFs) under the Public Utility
Regulatory Policies Act (PURPA) entered into
long-term gas supply agreements where the
pricing terms for a plant’s entire portfolio did not
reflect changes in gas market conditions. These
contracts often resulted in extensive litigation
and, in a number of instances, abrogation.45
Relational Contacts
Long-term bilateral contracts also offer an
opportunity to develop useful relationships
between buyer and seller.
The economic literature and various articles in
contract law discuss a class of contracts called
“relational” contracts. As stated by Schwartz,46
“[T]wo features define what lawyers mean
by a relational contract: incompleteness and
longevity.” “Incompleteness refers to the fact
that relational contracts do not provide all of the
aspects to provide a deterministic outcome to the
transactions in terms of the transfer of economic
goods, services, or payment.” In other words, the
contract does not completely specify the financial
or product obligations of the buyer and seller.
Rather, the contract determines the process and
procedures that will govern the legal relationship
between the parties.
Relational contracts often contain provisions that
allow for mutual or unilateral re-negotiation of
contract terms including pricing and contract
volumes. Other terms, including “market
out” or “regulatory out” provisions can also
play a role in relational contracts. The degree
of “incompleteness” of relational contracts
generally extends far beyond traditional force
majeure provisions.
Relational contracts have flourished in other
industries, such as the airline, automotive,
pharmaceuticals, biomedical and chemical
development industries. Strategic alliances
and joint ventures are often structured as
relational contracts because of the need to
address uncertainty and risk. Indeed some
contracts of this type have lasted for decades.
In these and other examples, parties to a
relationship seek to generate synergies without
vertically integrating through a merger—an
option that is, of course, unlikely to exist for
most major gas producers and consumers.
Relationship-Specific Investment
Switching costs can be very large in a non-homogeneous
product market. In energy, the market for coal is
often cited as an example. A coal-fired power plant
is “tuned” for specific attributes of the coal it is burning.
Water content, sulfur content, ash content, Btu content
and other physical attributes of the coal will all affect the
operation of the power plant to greater or lesser degrees.
Switching costs can also exist in homogeneous product
markets. These costs can arise from the “learning
process” that occurs between parties for procedures
and communications. In some markets, it can also
arise when small “brand” differentiations exist. In some
of the economic literature, costs associated with the
identification of alternative supplies are also included
as switching costs. In a sense, switching costs can be
considered a subset of transaction costs.
It is in the context of switching costs that much of the
discussion between gas producers or marketers and
large potential consumers, including industrial and power
plant facility owners, has occurred. In both cases, there
are significant costs that become sunk when a decision
is made to invest in and construct a gas-fired facility. As
such, industrial and power generation customers have
expressed concerns that the lack of any assurance that
natural gas prices in the United States will remain stable
and competitive with other options (e.g., with other energy
sources in the United States or with gas supplies that could
be accessed by locating facilities overseas) inhibits the
construction of gas-fired facilities. In the discussion,
potential buyers have considered long-term contracts with a
mechanism to provide price stability as a potential solution.
But this discussion involves two distinctly different concepts
of “switching costs.” In one case, switching costs relate to
broad market considerations such as the choice of energy
type and geographic location for investment. In this context,
switching costs can be quite significant. In the second
case, switching costs may be associated with moving from
one gas supplier to another. In this case, switching costs
are likely to be much smaller and potentially negligible.
Increased market liquidity and increased homogeneity in gas
quality specifications can significantly reduce the costs of
switching from one supplier to another.
In a sense, buyers interested in entering into a long-
term contract for gas supplies are seeking a guarantee or
warranty from the gas industry as a whole that gas prices
will remain competitive. However, a long-term contract
might not accomplish its economic goals in an effective
manner and could have unintended consequences.
Once a buyer contracts with a supplier, the buyer becomes
subject to some level of credit and default risk on the
part of the supplier. The contract does not—and cannot—
operate as a warranty from the broader gas industry.
To achieve a level of certainty, a buyer would need to
evaluate the ability of the supplier to fulfill the terms of
the contract. Only the largest suppliers would be very
likely to meet such a test.
52 Task Force on Ensuring Stable Natural Gas Markets
Task Force on Ensuring Stable Natural Gas Markets 53
GAS MARKETS IN WHICH
PARTIES MAY FIND IT MUTUALLY
ADVANTAGEOUS TO ENTER INTO
RELATIONAL CONTRACTS
AS WELL AS TO PARTICIPATE
IN JOINT VENTURES AND
PARTNERSHIPS MAY OFFER NEW
OPPORTUNITIES FOR PARTIES
TO ALLOCATE GAS PRICE RISK.
47 “Calpine Corporation to Acquire Sheridan Energy, Inc.; Calpine to Add 148 bcf of Proven Gas Reserves”, Business Wire, August 25, 1999.
48 “Municipalities Turn Again to Prepaid Gas Contracts”, David Schumacher, Chadbourne & Parke LLP, March 14, 2007. Examples include: Tennessee Energy Acquisition Corporation (TEAC) and Municipal Gas Authority of Georgia.
Gas markets in which parties may find it
mutually advantageous to enter into relational
contracts as well as to participate in joint
ventures and partnerships may offer new
opportunities for parties to allocate gas price
risk. A gas user can develop an effective hedge
against gas price movements and create an
implicit “long” position in gas production
by participating and having an interest in
production. But as is the case in any “hedging”
strategy, the user would be forgoing some
potential to benefit from an unexpected decline
in gas prices. Likewise, relationship-specific
contracts (or investments) may also create
“switching costs” for a buyer who switches
from one supplier to another.
Acquisition of Gas Reserves by Gas Consumers
Some large gas consumers have sought to
manage price risk by acquiring their own
physical reserves. Calpine, for example, has
utilized this strategy to hedge gas price risks
associated with its gas-fired power plants.47
Some firms that have regulated gas distribution
company subsidiaries have also developed
interests in the development of gas reserves.
Generally, gas distribution companies and gas
production companies are operated separately,
with separate accounting for purposes of gas
cost recovery. In at least one case, however,
the distribution company owns regulated
reserves and buys the gas on a cost of service
basis. In general, however, the performance
risk for gas production and prudence risk are
kept completely separate.
Long-Term Pre-Purchase of Gas Supply
A number of municipally owned gas distribution
companies, authorities or divisions of government
have taken a different approach to price stability.
Some, albeit a small minority, have entered into
pre-purchase agreements for multiple years of gas
supply.48 This can be particularly advantageous
to municipal residents since the purchase can be
financed with bonds that receive a measurable tax
advantage. This tax advantage can further reduce
the retail price ultimately paid by the municipal
LDC’s customers.
Long-Term Contracts for Regulated Entities
As noted previously, the decision to invest in
new gas-fired electric generation capacity
subjects power plant owners to certain risks
from increases in the market prices of gas. One
option is for the regulated electric utility to
enter into a long-term contract that provides for
more stable pricing.
54 Task Force on Ensuring Stable Natural Gas Markets
THE TASK FORCE
RECOMMENDS THAT STATE
REGULATORS REVISIT THE
FRAMEWORK FOR REGULATED
ENTITIES TO ENTER INTO
LONG-TERM GAS CONTRACTS
TO ENSURE THAT
OPPORTUNITIES TO CAPTURE
THE POTENTIAL PUBLIC
BENEFITS ASSOCIATED WITH
MORE DIVERSE LDC GAS
PORTFOLIOS ARE NOT BEING
UNREASONABLY FORECLOSED. 49 “Managing Gas Price Volatility”, The Brattle Group, prepared for the Task Force on Ensuring Stable Natural Gas Markets, July
2010. See Appendix B.
50 For example, the Colorado PUC recently approved a 10-year natural gas supply contract between Xcel Energy and Anadarko. The contract is part of a new resource plan, prompted by state legislation (HB-10-1365), that enables Xcel Energy to close four coal-fired units in the Denver region, switch one unit to natural gas and build a new gas-fired combined cycle plant with substantially lower air pollutant emissions. The Colorado PUC’s approval provides for cost recovery of payments under the contract with Anadarko, which contains a fixed price with an annual escalation adjustment, regardless of the future gas price trajectory. (See e.g., The Denver Post, Colorado PUC Adopts Plan to Switch Denver-area Power Plants to Natural Gas, 10 December 2010.)
51 In states with vertically integrated electric industries where the utility is required to make least-cost decisions about whether to build its own plant or buy from 3rd parties in competitive markets, and where state regulators want to support long-term gas contracting, regulators should take care to adopt long-term gas-contracting policies that do not introduce a bias toward the utility build option. This could happen where regulators allowed a utility to enter into long-term contracts, but not allow comparable protection for the third party competitors. Given the relatively high portion of total electric supply costs that could reside in fuel costs (versus capital recovery and operations/maintenance costs), such a regulatory policy could distort the playing field among the utility and its competitors. See Tierney, S. F. and Schatzki, T. “Competitive Procurement of Retail Electricity Supply: Recent Trends in State Policies and Utility Practices,” NARUC White Paper, July 2008. http://www.naruc.org/Publications/NARUC%20Competitive%20Procurement%20Final.pdf.
As a regulated entity, however, the electric utility
can be subject to risk in the form of “prudence”
reviews of the gas acquisition by state regulators.
One option to address this risk is to seek pre-
approval or a finding of prudence at the time
that the long-term contract is executed. In some
states, state regulators have legal authority to
grant pre-approval. In other states, they do
not, and legislation would be needed to grant
this authority.
Regulated investor-owned gas distribution
companies face a similar regulatory risk. For an
investor-owned gas LDC, entering into a long-
term contract is an asymmetric risk proposition
unless pre-approval is granted. Gas LDCs do
not earn their regulated return on the gas itself.
A gas LDC’s earnings are associated with the
services provided to customers associated with
installing the pipes, managing the operation,
and delivering reliable gas service to consumers
consistent with the tariff and the obligation
to serve.
If the LDC’s gas acquisition strategy is found
to be prudent, there is little or no upside return
associated with that performance. If, on the
other hand, the regulator finds that the utility
was imprudent, then the disallowance comes
directly out of the utility’s earnings. An analysis
of hedging developed for the Task Force found
that “While electric and gas utilities are making
far greater use of hedging tools relative to the
1990s, the hedging programs implemented by
many of them could almost certainly benefit
from some enhancements.”49
Without some opportunity for pre-approval,
there is an inherent tendency and incentive for
regulated LDCs to forgo a portfolio that includes
long-term contracts even if they provide some
element of price stability. Pre-approval creates
risks for regulators (and the customers they
represent) because they are in the position of
approving management decisions without having
access to all the information available to the LDCs.
In view of the foregoing, and as detailed below
(see section IV), the Task Force recommends
that state regulators revisit the framework for
regulated entities to enter into long-term gas
contracts to ensure that opportunities to capture
the potential public benefits associated with
more diverse LDC gas portfolios are not being
unreasonably foreclosed.50,51
iv. Contract Accounting Practices
In recent years, a number of stakeholders and
observers has called for greater reliance on
longer term contracts between gas suppliers
and purchasers as a means of dampening price
volatility and promoting greater market stability.
Task Force on Ensuring Stable Natural Gas Markets 55
52 The Brattle Group, FASB Accounting Rules and Implications for Natural Gas Purchase Agreements, February 7, 2011. See Appendix B.
53 Price Waterhouse Coopers, Guide to Accounting for Derivative Instruments and Hedging Activities, 2009-10
In the United States, these contracts constitute a
corporate asset that must be included in company
financial statements. To meet this requirement,
companies must follow generally accepted
accounting rules based on standards established
by the Financial Accounting Standards Board
(FASB), which operates under the authority of
the Securities and Exchange Commission (SEC).
From an accounting standpoint, natural gas
contracts are usually handled in one of two ways:52
� Fair value accounting, where the market value
of the gas contracts and associated obligations
are estimated each quarter. Under “mark- to-
market” accounting, which is the approach
generally used in periodic evaluations of fair
value, price fluctuations can cause frequent
changes in the balance sheet of a company
that enters into long-term contracts.
� The “normal purchases and sales exception”
in which costs are expensed as incurred and
remain fixed at those levels. As discussed
below, there are restrictions as to when and
how contracts can be eligible for this
exemption and when a company can choose
to use the exemption.
It is clear that fair market accounting makes
the balance sheet more volatile even when
an entity enters into long-term contracts for
natural gas. The accounting rules may therefore
inadvertently push companies away from long-
term contracts to the extent that management
wishes to avoid investor concerns arising from
volatility in the balance sheet.
It is difficult, however, to determine the degree
to which considerations related to balance
sheet volatility influence the decision to enter
into different types contracts in practice. For
regulated entities such as LDCs and electric
utilities, other factors, most notably the ability
to recover costs in regulated rates, appear to
be more influential. For non-regulated entities,
little information is available for assessing
whether concerns about disclosing balance
sheet fluctuations as a result of different
accounting treatments have a significant impact
on contracting decisions. The two options and
their implications are discussed below.
Fair Value Accounting
The FASB’s Accounting Standards Codification
(ASC 815), Derivatives and Hedging, generally
requires all entities to recognize derivative
instruments as assets or liabilities in their
financial statements and measure them at fair
value.53 Issued as an interim step in FASB’s
broader initiative to measure all financial
instruments at fair value, the guidance in ACS
815 is designed to address immediate problems
56 Task Force on Ensuring Stable Natural Gas Markets
THE PERIODIC PROCESS OF
MEASURING ASSETS AND
LIABILITIES IS REFERRED TO
AS “MARK-TO-MARKET”
SINCE THE FAIR VALUE OF AN
ASSET OR LIABILITY IS BASED
ON ITS MARKET PRICE.
54 This was the reason given by New Jersey Resources (the corporate parent of a LDC) when the SEC asked it to explain why it had switched from the normal purchases and sales exception to derivative accounting for all its contracts. See The Brattle Group, FASB Accounting Rules and Implications for Natural Gas Purchase Agreements, February 7, 2011, p.14. See Appendix B.
55 The Brattle Group report, in the Glossary, defines “net settlement” as “A contract with settlement provisions meeting one of the following criteria: - Neither party is required to deliver an asset that is associated with the underlying and that has a principal amount, stated amount, face value, number of shares, or other denomination that is equal to the notional amount (or the notional amount plus a premium or minus a discount). - One of the parties is required to deliver an asset of the type described in the first bullet above, but the contract specifies a market mechanism that facilitates net settlement. - One of the parties is required to deliver an asset of the type described in the first bullet above, but that asset is readily convertible to cash or is itself a derivative instrument.”
with the treatment of steadily more sophisticated
derivative instruments. As a result, any gas
purchase portfolio that utilizes futures, options,
swaps or other derivative products will require
fair market (e.g., mark-to-market) accounting for
consistent treatment.54 Many observers believe
that FASB’s goal is to achieve a full conversion to
fair value accounting by 2015.
Fair value accounting provides investors with
quarterly information about the fair value of
contracts and also provides significant risk
disclosure. Under fair value accounting, the
fair value of contracts is estimated each quarter.
This requires substantial documentation.
In addition, those who prepare financial
statements are required to identify the purpose
and risks of the derivative transactions.
The periodic process of measuring assets and
liabilities is referred to as “mark-to-market”
since the fair value of an asset or liability is
based on its market price. If no market exists for
the relevant asset or liability, similar assets or
liabilities or possibly an estimate of fair value are
used instead. Contracts must be valued based
on an index or with reference to an underlying
asset that is clearly and closely related to the
asset that is being purchased or sold.
The Normal Purchases and Sales Exception
ASC provides for an important exception to
the fair market accounting requirement called
“normal purchases and normal sales.” The
exception is available for contracts involving
the purchase or sale of something other than
a financial or derivative instrument. The
transaction must pertain to goods that are
expected to be used or sold by the reporting
company in the normal course of business.
Their costs are therefore expensed as incurred.
Under the normal purchases and sales
exception, fluctuations in natural gas prices
do not affect the buyer’s and/or the seller’s
financial statements.
Among the advantages of applying this exception
over fair value accounting is that the requirement
for quarterly contract valuation is avoided. As
such, accounting for the contract becomes
simpler and less costly. Further, under the
normal purchases and sales exception, natural
gas price fluctuations do not lead to fluctuations
in the reporting entity’s income statement or
balance sheet. Of course, judgment is required to
determine whether the exception is applicable
in particular cases.
To be eligible for the exception, the transacted
good must be delivered in quantities that (1)
are expected to be used or sold by the reporting
entity and (2) are reasonable in relation to the
reporting entity’s normal course of business.
Therefore, natural gas contracts that involve an
option to change contracted volumes and that
are not expected to net settle55 without complete
delivery (i.e., be offset against another contract)
typically do not qualify for the exception.
Task Force on Ensuring Stable Natural Gas Markets 57
HEDGING PROVIDES A THIRD
MAJOR TOOL FOR ENHANCING PRICE
STABILITY FOR BOTH BUYERS AND
SELLERS OF NATURAL GAS AND CAN
REDUCE PRICE UNCERTAINTY.
56 Ibid.
57 Includes information from The Brattle Group, FASB Accounting Rules and Implications for Natural Gas Purchase Agreements, February 7, 2011. See Appendix B.
A more complete discussion of these issues
is provided in the Brattle Group report,
which also includes several examples of how
different accounting treatments would affect
balance sheets under various scenarios.56
C. Financial and Physical Hedging57
Hedging provides a third major tool for
enhancing price stability for both buyers and
sellers of natural gas. Hedging enables market
participants to manage exposure to commodity
price volatility risk. Many firms and business
entities that require large volumes of one or
more commodities engage in hedging activity
to manage the price volatility risk. Simply put,
hedging can reduce price uncertainty.
i. Objectives, Costs and Limitations of Hedging
In its simplest form, hedging is a mechanism
that allows the buyer (or seller) to set the price
of a commodity at the time the hedge is created
for some or all of a commodity that will be
available at some time in the future. Hedging
can be accomplished with forward contracts for
physical delivery of the commodity or through
the use of financial derivatives.
There are a number of elements of a hedging
program that can be employed by any entity
to achieve its risk management objectives. A
number of financial instruments, generally
called financial derivatives, are available to
business entities for this purpose. While the
specific structure of these financial instruments
can be quite complicated and can differ widely,
the design and function of hedging instruments
are generally relatively straightforward: A firm
enters into a contractual obligation that involves
payment or receipt of an agreed sum to offset
the price risk associated with selling or buying
the physical commodity in the future.
Financial derivatives have pluses and minuses.
When properly applied, they provide risk
management at a manageable cost together with
an efficient method for transferring risk. The use
of derivatives allows for varying degrees of risk
mitigation ranging: Companies can eliminate
the vast majority of all risk from market volatility
or eliminate just the risk associated with the
most extreme price movements.
Like other forms of risk management and
insurance that are designed to address the
potential for price volatility, the level of
uncertainty that is mitigated using derivatives is
commensurate with the cost of the protection.
Some risk management strategies can be quite
costly, requiring an upfront payment that is
analogous to a significant insurance premium.
Other strategies may require the surrender of
financial gains in exchange for minimizing
Hedging Example: Use of a NYMEX Futures Contract
Futures contracts allow buyers and sellers to achieve price certainty.
For example, a buyer of a futures contact might purchase a January
2012 NYMEX futures contract today for $6.00/MMBtu, which
provides the right and obligation to purchase gas at that price at that
time. If Henry Hub spot prices in January 2012 turn out to be $8.00/
MMBtu, the buyer will experience a $2.00/MMBtu gain on the futures
contract, thereby achieving an effective gas price in January 2012 of
$6.00/MMbtu (assuming the buyer purchases spot gas for $8.00/MMBtu
at that time). Likewise, if Henry Hub prices are $4.00/MMBtu in January
2012, the buyer will experience a $2.00/MMBtu loss on the futures
contract, again achieving an effective gas price of $6.00/MMBtu.
58 Task Force on Ensuring Stable Natural Gas Markets
financial losses. In its pure form, hedging does
not provide a means to reduce the expected
fuel cost of an electric utility, but rather a
method to mitigate the impact of price volatility.
Fundamentally, sound risk management involves
constantly monitoring the risk-reward levels of
all the strategies in place for this purpose.
Nevertheless, strategies that utilize financial
derivatives generally have significant advantages
over strategies that rely exclusively on physical
forward contracts. They are generally more
liquid, meaning that derivatives positions can
be entered into and exited more easily.
Importantly, derivatives will also often have
lower transaction costs.
In the context of intermediate and long-term
gas price stability, hedging has significant
limitations. Relatively liquid markets for natural
gas derivatives exist for a year or two in the
future. However, there is no liquid market for
derivative products that extend for a period of
5 to 10 years and would thus be suitable for
managing price risk associated with investments
in long-lived facilities such as power plants,
refineries, or large industrial facilities. Thus,
while hedging is extremely important for
managing risks associated with short-term price
movements, it does not provide a complete
solution to the problem of price uncertainty in
the intermediate- and long-term.
ii. State Regulatory Treatment of Electric and Gas Utility Hedging Programs
Gas price movements and market instability
more generally present a number of significant
challenges to regulated entities such as electric
utilities and LDCs and their customers. For
customers, volatile gas prices complicate
household and small business budgets. Rising
gas prices also put pressure on the ability of
low-income customers to pay their utility bills.
For utilities, the potential for significant shifts
in gas prices from one heating season or year
to the next creates financial performance risks.
When gas prices rise significantly compared
to the previous year, the regulated entity faces
additional risk in three distinct areas:
1. Financial risk related to decreased throughput,
2. Risk created by an increase in uncollectable
accounts receivable (e.g., bad debt), and
3. Increases in operating costs associated with
increased shut-off and reconnect activity.
As hedging practices evolved, state Public Utility Commissions
were faced with establishing the process by which hedging
programs would be reviewed.* The National Regulatory Research
Institute (NRRI) describes the challenges and issues facing regulators in
the following manner:
1. How hedging fits in with the utility’s more traditional gas-management
strategy, which involves the purchase of both physical gas and
storage, with the latter functioning as a risk management tool
affecting both price and operating risk;
2. Establishing the prudent fixed budget for risk management programs;
3. Identifying, among the infinite number of alternatives, a specific risk
management strategy or set of strategies that is reasonable for a
particular LDC;
4. Establishing regulatory incentives for utility hedging and recovery
provisions pertaining to hedging program costs;
5. Specifying the operating features of a hedging program, which can
include specific safeguards or limits and reporting requirements;
6. Evaluating the effectiveness of different hedging tools, and;
7. Developing “prudence” standards by which to evaluate a utility’s
hedging practices.
* Kenneth W. Costello and John Cita, Use of Hedging by Local Gas
Distribution Companies: Basic Considerations and Regulatory Issues,
NRRI 01-08 (May 2001)
Task Force on Ensuring Stable Natural Gas Markets 59
State regulators have developed different
approaches for reviewing the hedging activities
of LDCs under their purview. The resulting
diversity and lack of uniformity in state
approaches makes it difficult to generalize but
certain observations regarding programs and
program review are possible. First, there is no
“inherently correct” level of hedging. Hedging
programs can provide various degrees of price
protection. There is also, however, “no free
lunch.” Greater amounts of price protection
can only be achieved with a commensurate
increase in forgone potential to benefit from
gas price reductions or with an increase in the
“upfront” costs incurred (analogous to
insurance premiums).
Second, the level of price protection being
sought through hedging should reflect the
risk tolerance of the regulators and the utility
operating as a proxy for customer preference.
Customers may have to pay higher rates
to offset the “upfront” cost— similar to an
insurance premium— for protection against
unanticipated cost increases. In the best case,
regulators and the utility create a process to
discuss, ex-ante, the objectives and the degree
of price protection desired. This type of process,
however, does not exist in all jurisdictions.
D. Potential Impact of Financial Reform on
Hedging Options
The Dodd–Frank Wall Street Reform and
Consumer Protection Act (Pub.L. 111-203,
H.R. 4173) was signed into law by President
Obama on July 21, 2010. The legislation, which
was intended as a response to the factors that
led to the financial crisis of 2009, is broad
and far-reaching in its scope. Though largely
animated by the desire to prevent future abuses
of non-commodity related derivatives, Title VII
of the legislation addresses the oversight and
regulation of financial derivatives (swaps) that
include natural gas and other energy products.
As such, it has the potential to significantly
alter the nature of—and cost of—price risk
mitigation for gas buyers and sellers alike.
Many of the details of the regulation have yet
to be promulgated by the Commodity Futures
Trading Commission (CFTC) and other
agencies with jurisdiction in the physical and
financial markets. Some of these details involve
important exceptions for end-users and bona
fide hedges, and the criteria used to establish
“de minimis” participants. The challenge for
the CFTC will be to craft rules that, on the
one hand, protect the American public and
the U.S. economy from destructive financial
practices and techniques without, on the other
hand, unduly restricting the use of bona fide
hedging tools in natural gas and other energy
commodity markets in ways that, by hindering
the efficient management of risk, would cause
producers and consumers to forego large
potential savings and discourage gas-related
investments going forward.
For example, although there is an expectation
that the “end user” exemption will apply to a
large number of risk management transactions
that rely on derivatives for hedging purposes,
parties will need to verify that individual
transactions meet the eligibility criteria for this
exemption. In addition, standardized futures
contracts in energy may become subject to
many additional regulatory requirements from
which they are currently exempt.
Under Title VII, the CFTC can require that any
swap, including natural gas and other energy
products, be cleared by a centralized clearing
house for any over-the-counter product ( i.e.,
a product that is not transacted through a
regulated exchange). The legislation and some
pre-proposals for regulation also contemplate,
among other things, imposing additional
(1) marginal and collateral requirements;
(2) capital requirements; (3) segregation of
funds, and (4) regulation of exchanges and
swap execution facilities (SEFs).
In addition, many market participants will
be subject to new standards of business
conduct and reporting requirements that
have yet to be promulgated by regulators.
These requirements are likely to create
costs associated with compliance and record
keeping as well as liabilities for the actions of
individuals within organization.
Economists who have examined the legislation
and related regulatory proposals have expressed
concerns regarding the unintended impact of
the new rules on:
� The administrative and economic costs
of hedging;
� The number and type of derivative contracts
that will be transacted in the markets;
60 Task Force on Ensuring Stable Natural Gas Markets
THE CHALLENGE FOR THE CFTC
WILL BE TO CRAFT RULES
THAT PROTECT THE AMERICAN
PUBLIC AND THE U.S.
ECONOMY FROM DESTRUCTIVE
FINANCIAL PRACTICES AND
TECHNIQUES WITHOUT UNDULY
RESTRICTING THE USE
OF BONA FIDE HEDGING
TOOLS IN NATURAL GAS
AND OTHER ENERGY
COMMODITY MARKETS.
Task Force on Ensuring Stable Natural Gas Markets 61
58 Here “basis risk” is defined as the risk associated with imperfect hedging using futures. Such risk could arise because of the difference between the asset whose price is to be hedged and the asset underlying the derivative, or because of a mismatch between the expiration date of the futures and the actual selling date of the asset. Under these conditions, the spot price of the asset and the futures price do not converge on the expiration date of the future. The amount by which the two quantities differ measures the value of the basis risk. In other words, the basis equals the spot price of the hedged asset minus the futures price of the contract.
� The liquidity of contacts that are available
and the costs associated with transaction as
manifested by larger bid-ask spreads;
� The potential for increased “unhedged”
basis risk;
� Increases in balance sheet risk for
participating entities;
� Increased risk for market users and their
customers.
In addition, the legislation brings a new
complexity to the regulatory landscape, creating
the potential for overlapping jurisdiction and
regulation for natural gas and energy market
participants. For example, transactions that
involve “basis risk”58 and physical gas could be
subjected to regulation by CFTC, FERC or both,
with different timelines for recordkeeping and
reporting. In short, while the new regulations
are still unclear, they risk limiting the ability of
gas market participants to manage price risk
through financial methods.
In general, our concern is that new regulations
could limit the availability and increase the
cost of tools that are used by market participants
to manage price risk and achieve greater price
stability. Higher costs are likely to affect even
those transactions that are exempt from the
new regulations. Exempt transactions are also
likely to be subject to increased costs and
reduced availability and liquidity due to the
capital that will be reserved and the margin
that will have to be posted by financial
institutions, swap dealers and major swap
participants who may be counterparties.
Based on these concerns, the Task Force
recommends that the CFTC and other federal
regulators exercise caution in adopting
measures that would limit the scope of bona
fide hedging opportunities in the natural
gas market. Given the potential benefits
associated with greater price stability, it is
important that producers (and consumers)
have an adequate range of affordable
commercial hedging opportunities to bring
this supply to the market at reasonable
prices. Regulations that unreasonably limit
such arrangements would be counter-
productive and could lead to more, not less,
price stability.
62 Task Force on Ensuring Stable Natural Gas Markets
C
I V.
CONCLUSIONS, RECOMMENDATIONS AND NEXT STEPS
Current understanding of the extent of the North
American natural gas resource base suggests
that the United States is well-positioned to take
advantage of natural gas as a low-polluting,
domestic fuel that can be used across the economy
in diverse, efficient applications. The investment
required to produce and make use of this resource
requires confidence that the resource can be
developed at moderate and stable prices. While
the available information suggests that the supply
of the underlying resource itself will go a long
way toward ensuring this outcome, the Task Force
offers the following findings and recommendations.
Task Force on Ensuring Stable Natural Gas Markets 63
BALANCED FISCAL AND REGULATORY
POLICIES WILL ENABLE AN
INCREASED SUPPLY OF NATURAL
GAS TO BE BROUGHT TO MARKET
AT MORE STABLE PRICES.
1. Recent developments allowing for the
economic extraction of natural gas from
shale formations reduce the susceptibility of
gas markets to price instability and provide
an opportunity to expand the efficient use of
natural gas in the United States
2. Government policy at the federal, state
and municipal levels should encourage
and facilitate the development of domestic
natural gas resources, subject to appropriate
environmental safeguards. Balanced fiscal and
regulatory policies will enable an increased
supply of natural gas to be brought to market
at more stable prices. Conversely, policies
that discourage the development of domestic
natural gas resources, that discourage
demand, or that drive or mandate inelastic
demand will disrupt the supply-demand
balance with adverse effects on the stability of
natural gas prices and investment decisions by
energy-intensive manufacturers.
3. The efficient use of natural gas has the potential
to reduce harmful air emissions, improve energy
security, and increase operating rates and levels of
capital investment in energy-intensive industries.
4. Public and private decision makers should
seek to remove barriers to the use of a diverse
portfolio of natural gas contracting structures
and hedging options. Long-term contracts and
hedging programs are valuable tools to manage
natural gas price risk. Policies, including tax
policy and accounting rules, that unnecessarily
restrict the use or raise the costs of these risk
management tools should be avoided.
5. Building on its 2005 resolution, the
National Association of Regulatory Utility
64 Task Force on Ensuring Stable Natural Gas Markets
59 National Association of Regulatory Utility Commissioners. Resolution on Long-Term Contracting. Adopted by the NARUC on November 16, 2005. http://www.naruc.org/Resolutions/GAS-1Long-TermContracting.pdf.
POLICY MAKERS SHOULD
RECOGNIZE THE IMPORTANT
ROLE OF NATURAL GAS
PIPELINE AND EXISTING
IMPORT AND STORAGE
INFRASTRUCTURE IN
PROMOTING STABLE
GAS PRICES.
Commissioners (NARUC) should consider
the merits of diversified natural gas portfolios,
including portfolios that provide for hedging
and longer-term natural gas contracts.59
Specifically, NARUC should examine:
a. Whether the current focus on shorter-
term contracts, first-of-the-month pricing
provisions, and spot market prices
supports the goal of enhancing price
stability for end users,
b. The pros and cons of long-term contracts
for regulators, regulated utilities and their
customers;
c. The regulatory risk issues associated with
long-term contracts and the issues of utility
commission pre-approval of long-term
contracts and look-back risk for regulated
entities; and
d. State practices that limit or encourage
long-term contracting.
6. As the Commodity Futures Trading
Commission (CFTC) implements financial
reform legislation, and specifically, Title VII
of the Dodd-Frank Wall Street Reform and
Consumer Protection Act of 2010 (Pub. L.
111-203), the CFTC should preserve the ability
of natural gas end users to cost-effectively
utilize the derivatives markets to manage their
commercial risk exposure. In addition, the
CFTC should consider the potential impact of
any new rulemaking on liquidity in the natural
gas derivatives market, as reduced liquidity
could have an adverse affect on natural gas
price stability.
7. Policy makers should recognize the
important role of natural gas pipeline and
existing import and storage infrastructure
in promoting stable gas prices. Policies
to support the development of a fully
functional and safe gas transmission and
storage infrastructure now and in the future,
including streamlined regulatory approval
and options for market-based rates for
new storage in the United States, should
be continued.
8. Finally, regulators should be mindful of the
lead time required for markets and market
participants to adjust to new policies.
Task Force on Ensuring Stable Natural Gas Markets 65
66 Task Force on Ensuring Stable Natural Gas Markets
WA. Work Shops and Participants
B. Commissioned Papers
V.
APPENDICES
Task Force on Ensuring Stable Natural Gas Markets 67
A. List of Work Shops and Participants
Work Shop List
Workshop #1 – The Economic
and Legal Background (May 20, 2010)
� An economic background of the
history of natural gas price volatility
from 1975 to present;
� The major supply and demand drivers
of natural gas price volatility
� The potential impact of North
American LNG imports and market
globalization on natural gas
price volatility;
� The supply and production outlook
for shale gas; and
� The potential for shale gas to
change the paradigm for natural
gas economics.
Workshop #2 - Private Sector
Options for Managing Price Stability
(July 28, 2010)
� An overview of existing commercial
options for producers and industrial
users to manage price volatility;
� Discussion of regulatory and
commercial barriers to more
widespread use of these options;
� An empirical review of the impact
of gas purchase terms and hedging
practices by major categories of
industrial users; and
� Case studies of major industrial
consumers.
Workshop #3 – Public Policy
Options for Managing Price Stability
(December 1, 2010)
� Lessons from other U.S. commodities
markets (e.g. cotton, copper, fuel oils);
� Lessons from other countries’
experience with natural gas price
volatility;
� An overview of regulatory and
legislative financial reforms and their
potential impact on current producer
and consumer hedging practices for
natural gas; and
� Recommend policy options for
managing price stability and identify
key insights from commissioned
research.
Work Shop Participants
Joel Bluestein, ICF International, Inc.; Kevin Book, ClearView Energy Partners; Geoff Bromaghim, American Clean Skies
Foundation; Ken Bromfield, The Dow Chemical Company; Stephen Brown, Resources for the Future; John Bryson, Edison
International (Ret.); Carlton Buford, The Williams Companies; Roni Cappadonna, Spectra Energy; Ralph Cavanagh, National
Resources Defense Council; Paul Cicio, Industrial Energy Consumers of America; Dave Conover, Bipartisan Policy Center;
Roger Cooper, Cleveland Park Policy Consulting, LLC; Peggy Duxbury, The William and Flora Hewlett Foundation; Jim Ford,
ConocoPhillips; Russ Ford, Shell Oil Company; Paula Gant, American Gas Association; Sara Glenn, Shell Oil Company; Frank
Graves, The Brattle Group, Inc.; Jason Grumet, Bipartisan Policy Center; Carl Haga, Southern Company; Byron Harris, Public
Service Commission of West Virginia; Bruce Henning, ICF International; Nate Hill, American Public Gas Association; Jerry
Hinkle, American Clean Skies Foundation; Rich Hoffman, Interstate Natural Gas Association of America; Colette Honorable,
Arkansas Public Service Commission; Paul Hughes, Southern Company; Sini Jacob, Pacific Gas & Electric; Marianne Kah,
ConocoPhillips; Bert Kalisch, American Public Gas Association; Alan Krupnick, Resources for the Future; Steve Levine, The Brattle
Group, Inc.; Lourdes Long, Bipartisan Policy Center; Chris McGill, American Gas Association; Ken Medlock, Rice University; Peter
Molinaro, The Dow Chemical Company; Sharon Nelson, Consumers Union (Ret.); Frank O’Sullivan, Massachusetts Institute of
Technology; John Pemberton, Southern Company; David Rosner, Bipartisan Policy Center; Donald Santa, Interstate Natural Gas
Association of America; Dave Schryver, American Public Gas Association; Peter Sheffield, Spectra Energy; Rick Smead, Navigant
Consulting Inc.; Gregory C. Staple, American Clean Skies Foundation; Todd Strauss, Pacific Gas & Electric; Norm Sydlowski,
Bipartisan Policy Center; Tracy Terry, Bipartisan Policy Center; Sue Tierney, Analysis Group, Inc.; Jeff Wallace, Southern Company;
Emily White, Bipartisan Policy Center; Austin Whitman, MJ Bradley & Associates, Inc.; Andrew Weissman, Carter, Ledyard and
Milburn; Bill Wince, Chesapeake Energy Marketing, Inc.; and Marty Zimmerman, University of Michigan.
68 Task Force on Ensuring Stable Natural Gas Markets
B. Commissioned Papers
Full versions of the commissioned papers listed in the table on the following
page can be accessed online at the following locations:
www.bipartisanpolicy.org/naturalgas www.cleanskies.org/PriceStabilityTaskForce
List of Commissioned Papers
Title Author Affiliation Summary
Natural Gas Price Volatility:
Lessons from Other Markets
Austin Whitman M.J. Bradley &
Associates, LLC
The report draws lessons from markets in the U.S., Europe,
and Asia to determine (1) how natural gas markets are
structured in the largest consuming regions of the world,
(2) the effect that exposure to natural gas prices has had
on corporate performance, and (3) how natural gas price
movements relate to those of other commodities.
Long-term Contracting for
Natural Gas
Bruce Henning ICF Consulting This paper defines the objectives and elements of long-term
contracts; traces the evolution of natural gas contracts;
assesses the economic value of long-term contracts;
analyzes the relationship between long-term contracts
and natural gas price stability; and examines natural gas
contracts for regulated entities.
Managing Natural Gas Price
Volatility
Steve Levine The Brattle Group This paper describes gas market risk characteristics;
identifies risk management principles and tools for
managing price volatility; describes risk management
processes and controls, and analyzes limitations in
managing price volatility; and compares industry hedging
practices.
New Approaches to
Reducing Natural Gas Price
Instability: Implementing
Legal, Regulatory and
Financial Options
Andrew Weissman Carter, Ledyard
and Milburn
The author identifies obstacles to reducing price instability
and opportunities to address long-term price uncertainty
and price spike risk through legal, regulatory, and financial
mechanisms.
Staff Memo assessing
the extent to which water
challenges, particularly
water availability, may
affect shale gas production
Lourdes Long BPC Staff How might water availability challenges constrain efforts to
expand shale gas production? This memo summarizes the
main water impacts associated with shale gas development
in order to address this central question.
Task Force on Ensuring Stable Natural Gas Markets 69
Title Author Affiliation Summary
Introduction to North
American Natural Gas
Markets Supply and Demand
Side Drivers of Volatility
Since the 1980s
Rick Smead Navigant
Consulting, Inc.
This paper examines the history of natural gas price
instability across three periods from 1976-2010, and identifies
fundamental changes in supply and demand that could
influence natural gas markets going forward.
Impact of LNG and Market
Globalization
Ken Medlock Rice University’s
James Baker
Institute for
Public Policy
This paper seeks to answer central questions about LNG
and market globalization: What are the potential impacts
of North American LNG imports and exports on natural gas
price volatility? Given the relative abundance of shale gas
in North America, is there any reason to believe that LNG
imports will rise in the coming years? In the US, how do
LNG, the domestic shale gas resource, and domestic storage
interact? If there are any potential adverse impacts of
globalized gas trade and increased LNG imports, are there
policy options available to mitigate the adverse impacts?
Abundant Shale Gas
Resources, Short-Term
Volatility, and Long-Term
Stability of Natural
Gas Prices
Stephen Brown
and Alan Krupnick
Resources
for the Future
This paper examines the extent to which natural gas prices
are likely to remain attractive to consumers. The authors
examine how the apparent abundance of natural gas and
projected growth of its use might affect natural gas prices,
production and consumption, using NEMS-RFF to model a
number of scenarios through 2030.
Policy Options that Could
Impact Natural Gas Supply
and Demand
Kevin Book ClearView Energy
Partners LLC
Scenario analysis of policies that could significantly
impact U.S. natural gas supply and/or demand; and to
quantitatively estimate the potential supply and/or demand
impacts of these policies.
FASB Accounting Rules and
Implications for Natural Gas
Purchase Agreements
Bente Villadsen
and Fiona Wang
The Brattle Group An overview of FASB accounting rules and their implications
for natural gas contracts; normal purchases and sales
exemption and fair value accounting treatment of natural
gas contracts.
The Impact of EPA Utility
MACT Rule on Natural
Gas Demand
Jennifer Macedonia
and Lourdes Long
BPC Staff A background on the MACT Standards and the results of
BPC modeling to analyze the impacts of the MACT rule on
electric utility generation and natural gas demand.
70 Task Force on Ensuring Stable Natural Gas Markets
design: www.katetallentdesign.com
The Bipartisan Policy Center and the American Clean Skies
Foundation have engaged MOSAIC, a carbon neutral EPA
Green Power Partner, for the production of this brochure, using
a waterless printing process. The brochure was printed on FSC
certified stock with 100% environmentally friendly soy-based inks.
750 1ST STREET, NE, SUITE 1100 WASHINGTON, D.C. 20002
T: 202-682-6294 | F: 202-682-3050WWW.CLEANSKIES.ORG
1225 I STREET, NW, SUITE 1000 WASHINGTON, D.C. 20005
T: 202-204-2400 | F: 202-637-9220WWW.BIPARTISANPOLICY.ORG